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Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2012 USD ($) shares
Trading Symbol	EXC
Entity Registrant Name	EXELON CORP
Entity Central Index Key	0001109357
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q4
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	663,368,958
Entity Public Float \| $	$ 59,092,745,316
Exelon Generation Co L L C [Member]
Entity Registrant Name	EXELON GENERATION CO LLC
Entity Central Index Key	0001168165
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Commonwealth Edison Co [Member]
Entity Registrant Name	COMMONWEALTH EDISON CO
Entity Central Index Key	0000022606
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	127,016,519
PECO Energy Co [Member]
Entity Registrant Name	PECO ENERGY CO
Entity Central Index Key	0000078100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	170,478,507

Consolidated Statements of Operations and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating revenues [Abstract]
Operating revenues from affiliates	$ 48,000	$ 9,000	$ 6,000
Total operating revenues	23,489,000	19,063,000	18,644,000
Operating expenses
Purchased power	10,157,000	7,267,000	6,435,000
Operating and maintenance	7,961,000	5,184,000	4,600,000
Operating and maintenance for regulatory required programs
Depreciation and amortization	1,881,000	1,347,000	2,075,000
Taxes other than income	1,019,000	785,000	808,000
Total operating expenses	21,018,000	14,583,000	13,918,000
Gain (loss) on equity method investments	(91,000)	(1,000)	0
Operating income	2,380,000	4,479,000	4,726,000
Other income and deductions
Interest expense	(903,000)	(701,000)	(792,000)
Interest expense to affiliates, net	(25,000)	(25,000)	(25,000)
Other, net	346,000	203,000	312,000
Total other income and deductions	(582,000)	(523,000)	(505,000)
Income before income taxes	1,798,000	3,956,000	4,221,000
Income taxes	627,000	1,457,000	1,658,000
Income from continuing operations
Discontinued operations
Income from discontinued operations, net
Net income	1,171,000	2,499,000	2,563,000
Net income (loss) attributable to noncontrolling interests and preferred security dividends	(11,000)	(4,000)	0
Net income on common stock	1,160,000	2,495,000	2,563,000
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	1,000	(5,000)	(11,000)
Actuarial loss reclassified to periodic cost	168,000	136,000	114,000
Transition obligation reclassified to periodic cost	2,000	4,000	3,000
Pension and non-pension postretirement benefit plans valuation adjustment	(371,000)	(250,000)	(288,000)
Change in unrealized gain (loss) on cash-flow hedges	(120,000)	88,000	(151,000)
Change in unrealized income (loss) on equity investments	1,000	0	0
Change in unrealized gain (loss) on marketable securities	2,000	0	(1,000)
Other comprehensive income (loss)	(317,000)	(27,000)	(334,000)
Comprehensive income	$ 854,000	$ 2,472,000	$ 2,229,000
Average shares of common stock outstanding:
Basic	816,000	663,000	661,000
Diluted	819,000	665,000	663,000
Earnings per average common share - basic
Income from continuing operations	$ 1.42	$ 3.76	$ 3.88
Earnings per average common share - diluted
Net income	1.42	3.75	3.87
Dividends per common share	$ 2.10	$ 2.10	$ 2.10
Exelon Generation Co L L C [Member]
Operating revenues [Abstract]
Operating revenues	$ 12,735,000	$ 9,286,000	$ 6,923,000
Operating revenues from affiliates	1,702,000	1,161,000	3,102,000
Total operating revenues	14,437,000	10,447,000	10,025,000
Operating expenses
Purchased power	7,061,000	3,589,000	3,463,000
Operating and maintenance	4,398,000	2,827,000	2,521,000
Operating and maintenance from affiliate	630,000	321,000	291,000
Depreciation and amortization	768,000	570,000	474,000
Taxes other than income	369,000	264,000	230,000
Total operating expenses	13,226,000	7,571,000	6,979,000
Gain (loss) on equity method investments	(91,000)	(1,000)
Operating income	1,120,000	2,875,000	3,046,000
Other income and deductions
Interest expense	(301,000)	(170,000)	(153,000)
Other, net	239,000	122,000	257,000
Total other income and deductions	(62,000)	(48,000)	104,000
Income before income taxes	1,058,000	2,827,000	3,150,000
Income taxes	500,000	1,056,000	1,178,000
Discontinued operations
Net income	558,000	1,771,000	1,972,000
Income (Loss) attributable to noncontrolling interest	4,000
Net income on membership interest	562,000	1,771,000	1,972,000
Pension and non-pension postretirement benefit plans:
Change in unrealized gain (loss) on cash-flow hedges	(403,000)	(98,000)	(144,000)
Change in unrealized income (loss) on equity investments	1,000
Other comprehensive income (loss)	(402,000)	(98,000)	(144,000)
Comprehensive income	156,000	1,673,000	1,828,000
Commonwealth Edison Co [Member]
Operating revenues [Abstract]
Operating revenues	5,441,000	6,054,000	6,202,000
Operating revenues from affiliates	2,000	2,000	2,000
Total operating revenues	5,443,000	6,056,000	6,204,000
Operating expenses
Purchased power	1,518,000	2,382,000	2,297,000
Purchased power from affiliate	789,000	653,000	1,010,000
Operating and maintenance	1,182,000	1,031,000	917,000
Operating and maintenance from affiliate	163,000	158,000	152,000
Depreciation and amortization	610,000	554,000	516,000
Taxes other than income	295,000	296,000	256,000
Total operating expenses	4,557,000	5,074,000	5,148,000
Operating income	886,000	982,000	1,056,000
Other income and deductions
Interest expense	(294,000)	(330,000)	(373,000)
Interest expense to affiliates, net	(13,000)	(15,000)	(13,000)
Other, net	39,000	29,000	24,000
Total other income and deductions	(268,000)	(316,000)	(362,000)
Income before income taxes	618,000	666,000	694,000
Income taxes	239,000	250,000	357,000
Discontinued operations
Net income	379,000	416,000	337,000
Pension and non-pension postretirement benefit plans:
Change in unrealized gain (loss) on marketable securities	1,000	0	(1,000)
Other comprehensive income (loss)	1,000	0	(1,000)
Comprehensive income	380,000	416,000	336,000
PECO Energy Co [Member]
Operating revenues [Abstract]
Operating revenues	3,183,000	3,715,000	5,514,000
Operating revenues from affiliates	3,000	5,000	5,000
Total operating revenues	3,186,000	3,720,000	5,519,000
Operating expenses
Purchased power	842,000	1,369,000	677,000
Purchased power from affiliate	533,000	495,000	2,085,000
Operating and maintenance	698,000	698,000	644,000
Operating and maintenance from affiliate	111,000	96,000	89,000
Depreciation and amortization	217,000	202,000	1,060,000
Taxes other than income	162,000	205,000	303,000
Total operating expenses	2,563,000	3,065,000	4,858,000
Operating income	623,000	655,000	661,000
Other income and deductions
Interest expense	(111,000)	(122,000)	(181,000)
Interest expense to affiliates, net	(12,000)	(12,000)	(12,000)
Other, net	8,000	14,000	8,000
Total other income and deductions	(115,000)	(120,000)	(185,000)
Income before income taxes	508,000	535,000	476,000
Income taxes	127,000	146,000	152,000
Discontinued operations
Net income	381,000	389,000	324,000
Preferred security dividends	(4,000)	(4,000)	(4,000)
Net income on common stock	377,000	385,000	320,000
Pension and non-pension postretirement benefit plans:
Amortization of realized loss on settled cash flow swaps	0	0	1,000
Change in unrealized gain (loss) on marketable securities	1,000	0	0
Other comprehensive income (loss)	1,000	0	(1,000)
Comprehensive income	382,000	389,000	323,000
Baltimore Gas and Electric Company [Member]
Operating revenues [Abstract]
Operating revenues	2,725,000	3,060,000	3,534,000
Operating revenues from affiliates	10,000	8,000	7,000
Total operating revenues	2,735,000	3,068,000	3,541,000
Operating expenses
Purchased power and fuel	973,000	1,245,000	1,719,000
Purchased power from affiliate	396,000	348,000	428,000
Operating and maintenance	622,000	530,000	469,000
Operating and maintenance from affiliate	106,000	150,000	126,000
Depreciation and amortization	298,000	274,000	249,000
Taxes other than income	208,000	207,000	200,000
Total operating expenses	2,603,000	2,754,000	3,191,000
Operating income	132,000	314,000	350,000
Other income and deductions
Interest expense	(144,000)	(129,000)	(131,000)
Other, net	23,000	26,000	25,000
Total other income and deductions	(121,000)	(103,000)	(106,000)
Income before income taxes	11,000	211,000	244,000
Income taxes	7,000	75,000	97,000
Discontinued operations
Net income	4,000	136,000	147,000
Preferred security dividends	(13,000)	(13,000)	(13,000)
Net income on common stock	(9,000)	123,000	134,000
Pension and non-pension postretirement benefit plans:
Comprehensive income	$ 4,000	$ 136,000	$ 147,000

Consolidated Statements of Operations and Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Prior service benefit reclassified to periodic cost, taxes	$ 1,000	$ (4,000)	$ (7,000)
Actuarial loss reclassified to periodic cost, taxes	110,000	93,000	79,000
Transition obligation reclassified to periodic cost, taxes	2,000	2,000	2,000
Pension and non-pension postretirement benefit plan valuation adjustment, taxes	(237,000)	(171,000)	(188,000)
Change in unrealized gain (loss) on cash flow hedges, taxes	(68,000)	39,000	(107,000)
Change in unrealized gain (loss) on marketable securities, taxes	(1,000)	0	0
Change in unrealized gain (loss) on equity investments taxes	1,000	0	0
Exelon Generation Co L L C [Member]
Gain on disposal of discontinued operations, taxes	0	0	0
Change in unrealized gain (loss) on cash flow hedges, taxes	(102,000)	(144,000)	302,000
Commonwealth Edison Co [Member]
Change in unrealized gain (loss) on marketable securities, taxes	0	0	0
PECO Energy Co [Member]
Change in unrealized gain (loss) on marketable securities, taxes	0	0	0
Amortization of realized gain on settled cash flow swaps, taxes	$ 0	$ 0	$ (1,000)

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities
Net income	$ 1,171,000	$ 2,499,000	$ 2,563,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	4,079,000	2,316,000	2,943,000
Impairment of assets held for sale	272,000	0	0
Deferred income taxes and amortization of investment tax credits	615,000	1,457,000	981,000
Net fair value changes related to derivatives	(604,000)	291,000	(88,000)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(157,000)	14,000	(105,000)
Other non-cash operating activities	1,383,000	770,000	609,000
Changes in assets and liabilities:
Accounts receivable	243,000	57,000	(232,000)
Inventories	26,000	(58,000)	(62,000)
Accounts payable, accrued expenses and other current liabilities	(632,000)	(254,000)	472,000
Option premiums paid, net	(114,000)	(3,000)	(124,000)
Counterparty collateral (posted) received, net	135,000	(344,000)	(155,000)
Income taxes	544,000	492,000	(543,000)
Pension and non-pension postretirement benefit contributions	(462,000)	(2,360,000)	(959,000)
Other assets and liabilities	(368,000)	(24,000)	(56,000)
Net cash flows provided by operating activities	6,131,000	4,853,000	5,244,000
Cash flows from investing activities
Capital expenditures	(5,789,000)	(4,042,000)	(3,326,000)
Proceeds from nuclear decommissioning trust fund sales	7,265,000	6,139,000	3,764,000
Investment in nuclear decommissioning trust funds	(7,483,000)	(6,332,000)	(3,907,000)
Cash acquired from Constellation	964,000
Proceeds from sale of Three Maryland Generating Stations	371,000
Acquisitions	(21,000)	(387,000)	(893,000)
Proceeds from sales of investments	28,000	6,000	28,000
Purchases of investments	(13,000)	(4,000)	(22,000)
Change in restricted cash	(34,000)	(3,000)	423,000
Other investing activities	136,000	20,000	39,000
Net cash flows provided by (used in) investing activities	(4,576,000)	(4,603,000)	(3,894,000)
Cash flows from financing activities
Payment of accounts receivable agreement	(15,000)
Changes in short-term debt	(197,000)	161,000	(155,000)
Issuance of long-term debt	2,027,000	1,199,000	1,398,000
Retirement or repayment of long-term debt	(1,145,000)	(789,000)	(828,000)
Retirement of long-term debt of variable interest entity	0	0	(806,000)
Retirement of long-term debt to financing affiliates	0	0	0
Dividends paid on common stock	(1,716,000)	(1,393,000)	(1,389,000)
Proceeds from employee stock plans	72,000	38,000	48,000
Purchase of treasury stock	0	0	0
Purchase of forward contract in relation to certain treasury stock	0	0	0
Other financing activities	(111,000)	(62,000)	(16,000)
Net cash flows used in financing activities	(1,085,000)	(846,000)	(1,748,000)
Increase (decrease) in cash and cash equivalents	470,000	(596,000)	(398,000)
Cash and cash equivalents at beginning of period	1,016,000	1,612,000	2,010,000
Cash and cash equivalents at end of period	1,486,000	1,016,000	1,612,000
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	558,000	1,771,000	1,972,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	2,966,000	1,539,000	1,341,000
Impairment of assets held for sale	272,000	0	0
Deferred income taxes and amortization of investment tax credits	408,000	551,000	741,000
Net fair value changes related to derivatives	(611,000)	291,000	(88,000)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(157,000)	14,000	(105,000)
Other non-cash operating activities	537,000	421,000	182,000
Changes in assets and liabilities:
Accounts receivable	248,000	(122,000)	0
Receivables from and payables to affiliates, net	39,000	208,000	(5,000)
Inventories	31,000	(47,000)	(70,000)
Accounts payable, accrued expenses and other current liabilities	(499,000)	34,000	(18,000)
Option premiums paid, net	(114,000)	(3,000)	(124,000)
Counterparty collateral (posted) received, net	95,000	(410,000)	(1,000)
Income taxes	114,000	193,000	(303,000)
Pension and non-pension postretirement benefit contributions	(178,000)	(1,070,000)	(445,000)
Other assets and liabilities	(128,000)	(57,000)	(45,000)
Net cash flows provided by operating activities	3,581,000	3,313,000	3,032,000
Cash flows from investing activities
Capital expenditures	(3,554,000)	(2,491,000)	(1,883,000)
Proceeds from nuclear decommissioning trust fund sales	7,265,000	6,139,000	3,764,000
Investment in nuclear decommissioning trust funds	(7,483,000)	(6,332,000)	(3,907,000)
Cash acquired from Constellation	708,000
Proceeds from sale of Three Maryland Generating Stations	371,000
Acquisitions	(21,000)	(387,000)	(893,000)
Change in restricted cash	4,000	0	4,000
Other investing activities	81,000	(6,000)	19,000
Net cash flows provided by (used in) investing activities	(2,629,000)	(3,077,000)	(2,896,000)
Cash flows from financing activities
Changes in short-term debt	(52,000)
Issuance of long-term debt	1,076,000	0	898,000
Retirement or repayment of long-term debt	(145,000)	(2,000)	(215,000)
Distribution to member	(1,626,000)	(172,000)	(1,508,000)
Contributions from member	48,000	30,000	62,000
Other financing activities	(78,000)	(52,000)	(16,000)
Net cash flows used in financing activities	(777,000)	(196,000)	(779,000)
Increase (decrease) in cash and cash equivalents	175,000	40,000	(643,000)
Cash and cash equivalents at beginning of period	496,000	456,000	1,099,000
Cash and cash equivalents at end of period	671,000	496,000	456,000
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	379,000	416,000	337,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	610,000	554,000	517,000
Deferred income taxes and amortization of investment tax credits	270,000	700,000	582,000
Other non-cash operating activities	252,000	184,000	238,000
Changes in assets and liabilities:
Accounts receivable	24,000	5,000	(46,000)
Receivables from and payables to affiliates, net	(18,000)	(287,000)	(55,000)
Inventories	(11,000)	(9,000)	(1,000)
Accounts payable, accrued expenses and other current liabilities	59,000	(84,000)	342,000
Counterparty collateral (posted) received, net	40,000	66,000	(154,000)
Income taxes	9,000	223,000	(233,000)
Pension and non-pension postretirement benefit contributions	(138,000)	(977,000)	(317,000)
Other assets and liabilities	(142,000)	45,000	(133,000)
Net cash flows provided by operating activities	1,334,000	836,000	1,077,000
Cash flows from investing activities
Capital expenditures	(1,246,000)	(1,028,000)	(962,000)
Proceeds from sales of investments	28,000	6,000	28,000
Purchases of investments	(13,000)	(4,000)	(22,000)
Other investing activities	19,000	19,000	17,000
Net cash flows provided by (used in) investing activities	(1,212,000)	(1,007,000)	(939,000)
Cash flows from financing activities
Changes in short-term debt	0	0	(155,000)
Issuance of long-term debt	350,000	1,199,000	500,000
Retirement or repayment of long-term debt	(450,000)	(537,000)	(213,000)
Contributions from parent	0	0	2,000
Dividends paid on common stock	(105,000)	(300,000)	(310,000)
Other financing activities	(7,000)	(7,000)	(3,000)
Net cash flows used in financing activities	(212,000)	355,000	(179,000)
Increase (decrease) in cash and cash equivalents	(90,000)	184,000	(41,000)
Cash and cash equivalents at beginning of period	234,000	50,000	91,000
Cash and cash equivalents at end of period	144,000	234,000	50,000
PECO Energy Co [Member]
Cash flows from operating activities
Net income	381,000	389,000	324,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	217,000	202,000	1,060,000
Deferred income taxes and amortization of investment tax credits	37,000	253,000	(400,000)
Other non-cash operating activities	125,000	100,000	108,000
Changes in assets and liabilities:
Accounts receivable	(14,000)	225,000	(212,000)
Receivables from and payables to affiliates, net	13,000	(217,000)	86,000
Inventories	21,000	0	9,000
Accounts payable, accrued expenses and other current liabilities	(47,000)	34,000	85,000
Income taxes	174,000	(45,000)	118,000
Pension and non-pension postretirement benefit contributions	(45,000)	(137,000)	(106,000)
Other assets and liabilities	16,000	14,000	78,000
Net cash flows provided by operating activities	878,000	818,000	1,150,000
Cash flows from investing activities
Capital expenditures	(422,000)	(481,000)	(545,000)
Changes in intercompany money pool	82,000	(82,000)	0
Change in restricted cash	2,000	(2,000)	414,000
Other investing activities	10,000	8,000	11,000
Net cash flows provided by (used in) investing activities	(328,000)	(557,000)	(120,000)
Cash flows from financing activities
Changes in short-term debt	(15,000)	0	0
Issuance of long-term debt	350,000	0	0
Retirement or repayment of long-term debt	(375,000)	(250,000)	0
Retirement of long-term debt of variable interest entity	0	0	(806,000)
Retirement of long-term debt to financing affiliates	0	0	0
Contributions from parent	9,000	18,000	43,000
Dividends paid on common stock	(343,000)	(348,000)	(224,000)
Dividends paid on preferred securities	(4,000)	(4,000)	(4,000)
Repayment of receivable from parent	0	0	180,000
Other financing activities	(4,000)	(5,000)	0
Net cash flows used in financing activities	(382,000)	(589,000)	(811,000)
Increase (decrease) in cash and cash equivalents	168,000	(328,000)	219,000
Cash and cash equivalents at beginning of period	194,000	522,000	303,000
Cash and cash equivalents at end of period	362,000	194,000	522,000
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	4,000	136,000	147,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	298,000	274,000	249,000
Deferred income taxes and amortization of investment tax credits	104,000	145,000	299,000
Other non-cash operating activities	193,000	129,000	144,000
Changes in assets and liabilities:
Accounts receivable	(45,000)	60,000	(95,000)
Receivables from and payables to affiliates, net	26,000	(44,000)	(24,000)
Inventories	25,000	(10,000)	8,000
Accounts payable, accrued expenses and other current liabilities	(33,000)	(21,000)	(66,000)
Income taxes	14,000	35,000	(56,000)
Pension and non-pension postretirement benefit contributions	(16,000)	(67,000)	(214,000)
Other assets and liabilities	(85,000)	(161,000)	(63,000)
Net cash flows provided by operating activities	485,000	476,000	329,000
Cash flows from investing activities
Capital expenditures	(582,000)	(592,000)	(508,000)
Changes in intercompany money pool			315,000
Proceeds from sales of investments	0	0	21,000
Change in restricted cash	0	0	(5,000)
Other investing activities	9,000	0	0
Net cash flows provided by (used in) investing activities	(573,000)	(592,000)	(177,000)
Cash flows from financing activities
Changes in short-term debt	0	0	(46,000)
Issuance of long-term debt	250,000	300,000	0
Retirement or repayment of long-term debt	(173,000)	(82,000)	(57,000)
Contributions from parent	66,000	0	0
Dividends paid on common stock	0	(85,000)	0
Dividends paid on preferred securities	(13,000)	(13,000)	(13,000)
Other financing activities	(2,000)	(5,000)	0
Net cash flows used in financing activities	128,000	115,000	(116,000)
Increase (decrease) in cash and cash equivalents	40,000	(1,000)	36,000
Cash and cash equivalents at beginning of period	49,000	50,000	14,000
Cash and cash equivalents at end of period	$ 89,000	$ 49,000	$ 50,000

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 1,411,000	$ 1,016,000
Cash and cash equivalents of variable interest entities	75,000
Restricted cash and investments	86,000	40,000
Restricted cash and investments of variable interest entity	47,000
Accounts receivable, net
Customer	2,787,000	1,613,000
Other	1,147,000	1,000,000
Accounts receivable of variable interest entities	292,000
Mark-to-market derivative assets	938,000	432,000
Unamortized energy contracts assets	886,000	16,000
Inventories, net
Fossil fuel	246,000	208,000
Materials and supplies	768,000	656,000
Deferred income taxes	131,000	0
Regulatory assets	759,000	390,000
Other	560,000	342,000
Total current assets	10,133,000	5,713,000
Property, plant and equipment, net	45,186,000	32,570,000
Deferred debits and other assets
Regulatory assets	6,497,000	4,518,000
Nuclear decommissioning trust funds	7,248,000	6,507,000
Investments	1,184,000	751,000
Investments in affiliates	22,000	15,000
Investment in CENG	1,849,000
Goodwill	2,625,000	2,625,000
Mark-to-market derivative assets	937,000	650,000
Pledged assets for Zion Station decommissioning	614,000	734,000
Unamortized energy contracts assets	1,073,000	424,000
Other	1,128,000	488,000
Deferred income taxes	58,000	0
Total deferred debits and other assets	23,235,000	16,712,000
Total assets	78,554,000	54,995,000
Current liabilities
Short-term borrowings	0	163,000
Short-term notes payable - accounts receivable agreement	210,000	225,000
Long-term debt due within one year	975,000	828,000
Long-term debt of variable interest entities due within one year	72,000
Accounts payable	2,446,000	1,444,000
Accounts payable of variable interest entities	202,000
Accrued expenses	1,800,000	1,255,000
Payables to affiliates	88,000	5,000
Deferred income taxes	58,000	1,000
Regulatory liabilities	321,000	197,000
Dividends payable	4,000	349,000
Mark-to-market derivative liabilities	352,000	112,000
Mark-to-market derivative liabilities with affiliate	0
Unamortized energy contract liabilities	455,000
Other	889,000	560,000
Total current liabilities	7,784,000	5,134,000
Long-term debt	17,190,000	11,799,000
Long-term debt of variable financing trusts	508,000	390,000
Long-term debt of variable interest entity	648,000
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,551,000	8,253,000
Asset retirement obligations	5,074,000	3,884,000
Pension obligations	3,428,000	2,194,000
Non-pension postretirement benefit obligations	2,662,000	2,263,000
Spent nuclear fuel obligation	1,020,000	1,019,000
Regulatory liabilities	3,981,000	3,627,000
Mark-to-market derivative liabilities	281,000	126,000
Unamortized energy contract liabilities	528,000
Payable for Zion Station decommissioning	432,000	563,000
Other	1,650,000	1,268,000
Total deferred credits and other liabilities	30,607,000	23,197,000
Total liabilities	56,737,000	40,520,000
Commitments and contingencies	0	0
Preferred securities	87,000	87,000
Shareholders' equity
Common stock	16,632,000	9,107,000
Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively)	(2,327,000)	(2,327,000)
Retained earnings	9,893,000	10,055,000
Accumulated other comprehensive income (loss), net	(2,767,000)	(2,450,000)
Total shareholders' equity	21,431,000	14,385,000
BGE preference stock not subject to mandatory redemption	193,000
Noncontrolling interest	106,000	3,000
Total equity	21,730,000	14,388,000
Total liabilities and shareholders' equity	78,554,000	54,995,000
Member's equity
Accumulated other comprehensive income (loss), net	(2,767,000)	(2,450,000)
Noncontrolling interest	106,000	3,000
Removal Costs [Member]
Current liabilities
Regulatory liabilities	97,000	61,000
Deferred credits and other liabilities
Regulatory liabilities	1,406,000	1,185,000
Exelon Generation Co L L C [Member]
Current assets
Cash and cash equivalents	596,000	496,000
Cash and cash equivalents of variable interest entities	75,000
Restricted cash and cash equivalents	0	5,000
Restricted cash and investments of variable interest entity	16,000
Accounts receivable, net
Customer	1,482,000	578,000
Other	472,000	257,000
Accounts receivable of variable interest entities	292,000
Mark-to-market derivative assets	938,000	432,000
Mark-to-market derivative assets with affiliates	226,000	503,000
Receivables from affiliates	141,000	109,000
Unamortized energy contracts assets	886,000	16,000
Inventories, net
Fossil fuel	130,000	120,000
Materials and supplies	626,000	556,000
Other	331,000	145,000
Total current assets	6,211,000	3,217,000
Property, plant and equipment, net	19,531,000	13,475,000
Deferred debits and other assets
Nuclear decommissioning trust funds	7,248,000	6,507,000
Investments	420,000	42,000
Investment in CENG	1,849,000
Mark-to-market derivative assets	924,000	635,000
Mark-to-market derivative assets with affiliates	0	191,000
Prepaid pension asset	1,975,000	2,068,000
Pledged assets for Zion Station decommissioning	614,000	734,000
Unamortized energy contracts assets	1,073,000	424,000
Other	836,000	140,000
Total deferred debits and other assets	14,939,000	10,741,000
Total assets	40,681,000	27,433,000
Current liabilities
Short-term borrowings		2,000
Long-term debt due within one year	24,000	3,000
Long-term debt of variable interest entities due within one year	4,000
Accounts payable	1,346,000	753,000
Accounts payable of variable interest entities	202,000
Accrued expenses	1,116,000	779,000
Payables to affiliates	193,000	58,000
Deferred income taxes	128,000	244,000
Mark-to-market derivative liabilities	334,000	103,000
Mark-to-market derivative liabilities with affiliate	0
Unamortized energy contract liabilities	378,000
Other	372,000	202,000
Total current liabilities	4,097,000	2,144,000
Long-term debt	5,245,000	3,674,000
Long-term debt to affiliate	2,007,000
Long-term debt of variable interest entity	203,000
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,398,000	3,966,000
Asset retirement obligations	4,938,000	3,767,000
Non-pension postretirement benefit obligations	755,000	703,000
Spent nuclear fuel obligation	1,020,000	1,019,000
Payables to affiliates	2,397,000	2,222,000
Mark-to-market derivative liabilities	232,000	29,000
Unamortized energy contract liabilities	516,000
Payable for Zion Station decommissioning	432,000	563,000
Other	776,000	638,000
Total deferred credits and other liabilities	16,464,000	12,907,000
Total liabilities	28,016,000	18,725,000
Commitments and contingencies	0	0
Shareholders' equity
Accumulated other comprehensive income (loss), net	513,000	915,000
Noncontrolling interest	108,000	5,000
Member's equity
Membership interest	8,876,000	3,556,000
Undistributed earnings	3,168,000	4,232,000
Accumulated other comprehensive income (loss), net	513,000	915,000
Total member's equity	12,557,000	8,703,000
Noncontrolling interest	108,000	5,000
Total equity	12,665,000	8,708,000
Total liabilities and equity	40,681,000	27,433,000
Commonwealth Edison Co [Member]
Current assets
Cash and cash equivalents	144,000	234,000
Restricted cash and cash equivalents	0	3,000
Accounts receivable, net
Customer	539,000	655,000
Other	452,000	385,000
Inventories, net
Inventories, net	91,000	81,000
Deferred income taxes	83,000	61,000
Counterparty collateral deposited	53,000	90,000
Regulatory assets	388,000	657,000
Other	25,000	22,000
Total current assets	1,775,000	2,188,000
Property, plant and equipment, net	13,826,000	13,121,000
Deferred debits and other assets
Regulatory assets	666,000	699,000
Investments	8,000	21,000
Investments in affiliates	6,000	6,000
Goodwill	2,625,000	2,625,000
Receivable from affiliate	2,039,000	1,860,000
Mark-to-market derivative assets	0	0
Prepaid pension asset	1,661,000	1,803,000
Other	299,000	315,000
Total deferred debits and other assets	7,304,000	7,329,000
Total assets	22,905,000	22,638,000
Current liabilities
Short-term borrowings	0	0
Long-term debt due within one year	252,000	450,000
Accounts payable	379,000	325,000
Accrued expenses	295,000	318,000
Payables to affiliates	97,000	111,000
Customer deposits	136,000	136,000
Regulatory liabilities	130,000	137,000
Mark-to-market derivative liabilities	18,000	9,000
Mark-to-market derivative liabilities with affiliate	226,000	503,000
Other	122,000	82,000
Total current liabilities	1,655,000	2,071,000
Long-term debt	5,315,000	5,215,000
Long-term debt of variable financing trusts	206,000	206,000
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,272,000	3,993,000
Asset retirement obligations	99,000	89,000
Non-pension postretirement benefit obligations	273,000	271,000
Regulatory liabilities	3,229,000	3,042,000
Mark-to-market derivative liabilities	49,000	97,000
Mark-to-market derivative liabilities with affiliate	0	191,000
Other	484,000	426,000
Total deferred credits and other liabilities	8,406,000	8,109,000
Total liabilities	15,582,000	15,601,000
Commitments and contingencies	0	0
Shareholders' equity
Common stock	1,588,000	1,588,000
Other paid-in capital	5,014,000	5,003,000
Retained earnings	721,000	447,000
Accumulated other comprehensive income (loss), net	0	(1,000)
Total shareholders' equity	7,323,000	7,037,000
Total liabilities and shareholders' equity	22,905,000	22,638,000
Member's equity
Accumulated other comprehensive income (loss), net	0	(1,000)
Commonwealth Edison Co [Member] \| Removal Costs [Member]
Current liabilities
Regulatory liabilities	75,000	61,000
Deferred credits and other liabilities
Regulatory liabilities	1,192,000	1,185,000
PECO Energy Co [Member]
Current assets
Cash and cash equivalents	362,000	194,000
Restricted cash and cash equivalents	0	2,000
Accounts receivable, net
Customer	364,000	380,000
Other	161,000	376,000
Inventories, net
Fossil fuel	65,000	87,000
Materials and supplies	19,000	18,000
Deferred income taxes	40,000	25,000
Receivable from Exelon intercompany money pool	0	82,000
Prepaid utility taxes	21,000	1,000
Regulatory assets	32,000	39,000
Other	30,000	39,000
Total current assets	1,094,000	1,243,000
Property, plant and equipment, net	6,078,000	5,874,000
Deferred debits and other assets
Regulatory assets	1,378,000	1,216,000
Investments	22,000	22,000
Investments in affiliates	8,000	8,000
Receivable from affiliate	360,000	365,000
Prepaid pension asset	373,000	382,000
Other	40,000	46,000
Total deferred debits and other assets	2,181,000	2,039,000
Total assets	9,353,000	9,156,000
Current liabilities
Short-term notes payable - accounts receivable agreement	210,000	225,000
Long-term debt due within one year	300,000	375,000
Long-term debt to PECO Energy Transition Trust due within one year	0	0
Accounts payable	244,000	262,000
Accrued expenses	82,000	83,000
Payables to affiliates	76,000	62,000
Deferred income taxes	0	0
Customer deposits	51,000	53,000
Regulatory liabilities	169,000	60,000
Mark-to-market derivative liabilities	0	0
Mark-to-market derivative liabilities with affiliate	0	0
Other	26,000	25,000
Total current liabilities	1,158,000	1,145,000
Long-term debt	1,647,000	1,597,000
Long-term debt of variable financing trusts	184,000	184,000
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,331,000	2,170,000
Asset retirement obligations	29,000	28,000
Non-pension postretirement benefit obligations	284,000	288,000
Regulatory liabilities	538,000	585,000
Mark-to-market derivative liabilities	0	0
Mark-to-market derivative liabilities with affiliate	0	0
Other	113,000	134,000
Total deferred credits and other liabilities	3,295,000	3,205,000
Total liabilities	6,284,000	6,131,000
Preferred securities	87,000	87,000
Shareholders' equity
Common stock	2,388,000	2,379,000
Receivable from parent	0	0
Retained earnings	593,000	559,000
Accumulated other comprehensive income (loss), net	1,000	0
Total shareholders' equity	2,982,000	2,938,000
Total liabilities and shareholders' equity	9,353,000	9,156,000
Member's equity
Accumulated other comprehensive income (loss), net	1,000	0
PECO Energy Co [Member] \| Removal Costs [Member]
Current liabilities
Regulatory liabilities	0	0
Deferred credits and other liabilities
Regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member]
Current assets
Cash and cash equivalents	89,000	49,000
Restricted cash and investments of variable interest entity	30,000	30,000
Accounts receivable, net
Customer	401,000	428,000
Other	117,000	90,000
Income taxes receivable	3,000	21,000
Inventories, net
Fossil fuel	51,000	74,000
Materials and supplies	31,000	34,000
Deferred income taxes	1,000
Prepaid utility taxes	57,000	56,000
Regulatory assets	185,000	175,000
Other	8,000	12,000
Total current assets	973,000	969,000
Property, plant and equipment, net	5,498,000	5,132,000
Deferred debits and other assets
Regulatory assets	522,000	551,000
Investments	5,000	0
Investments in affiliates	8,000	8,000
Prepaid pension asset	467,000	514,000
Other	26,000	29,000
Total deferred debits and other assets	1,028,000	1,102,000
Total assets	7,499,000	7,203,000
Current liabilities
Long-term debt due within one year	400,000	110,000
Long-term debt of variable interest entities due within one year	67,000	63,000
Accounts payable	195,000	210,000
Accrued expenses	106,000	110,000
Payables to affiliates	65,000	41,000
Deferred income taxes	0	59,000
Customer deposits	71,000	84,000
Regulatory liabilities	22,000	19,000
Other	47,000	38,000
Total current liabilities	973,000	734,000
Long-term debt	1,446,000	1,596,000
Long-term debt of variable financing trusts	258,000	258,000
Long-term debt of variable interest entity	265,000	332,000
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,658,000	1,491,000
Asset retirement obligations	8,000	1,000
Non-pension postretirement benefit obligations	229,000	233,000
Regulatory liabilities	214,000	201,000
Other	90,000	56,000
Total deferred credits and other liabilities	2,199,000	1,982,000
Total liabilities	5,141,000	4,902,000
Shareholders' equity
Common stock	1,360,000	1,294,000
Retained earnings	808,000	817,000
Total shareholders' equity	2,168,000	2,111,000
BGE preference stock not subject to mandatory redemption	190,000	190,000
Total equity	2,358,000	2,301,000
Total liabilities and shareholders' equity	7,499,000	7,203,000
Baltimore Gas and Electric Company [Member] \| Removal Costs [Member]
Current liabilities
Regulatory liabilities	22,000	18,000
Deferred credits and other liabilities
Regulatory liabilities	$ 214,000	$ 200,000

Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral	$ 289,000	$ 346,000
Shareholders' equity
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	854,781,389	663,368,958
Treasury Stock, Shares held	35,000,000	35,000,000
PECO Energy Co [Member]
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral	$ 289,000	$ 329,000
Shareholders' equity
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Shareholders' equity
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares outstanding	1,000	1,000

Consolidated Statement of Changes in Shareholders Equity (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock [Member]	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive (Loss) Income, Net	Noncontrolling Interest	Preference Stock Not Subject To Mandatory Redemption [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member] Undistributed Earnings [Member]	Exelon Generation Co L L C [Member] Membership Interest [Member]	Exelon Generation Co L L C [Member] Accumulated Other Comprehensive (Loss) Income, Net	Exelon Generation Co L L C [Member] Noncontrolling Interest	PECO Energy Co [Member]	PECO Energy Co [Member] Common Stock [Member]	PECO Energy Co [Member] Receivable From Parent [Member]	PECO Energy Co [Member] Retained Earnings	PECO Energy Co [Member] Accumulated Other Comprehensive (Loss) Income, Net	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member] Common Stock [Member]	Commonwealth Edison Co [Member] Accumulated Other Comprehensive (Loss) Income, Net	Commonwealth Edison Co [Member] Other Paid-In Capital	Commonwealth Edison Co [Member] Retained Deficit Unappropriated	Commonwealth Edison Co [Member] Retained Earnings Appropriated	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member] Undistributed Earnings [Member]	Baltimore Gas and Electric Company [Member] Common Stock [Member]	Baltimore Gas and Electric Company [Member] Membership Interest [Member]	Baltimore Gas and Electric Company [Member] Noncontrolling Interest	Baltimore Gas and Electric Company [Member] Preference Stock Not Subject To Mandatory Redemption [Member]
Beginning Balance at Dec. 31, 2009								$ 6,792,000	$ 2,169,000	$ 3,464,000	$ 1,157,000	$ 2,000
Beginning Balance at Dec. 31, 2009	$ 12,640,000	$ 8,923,000	$ (2,328,000)	$ 8,134,000	$ (2,089,000)																			$ 2,147,000				$ 18,000	$ 190,000
Beginning Balance at Dec. 31, 2009		694,565
Beginning Balance at Dec. 31, 2009													$ 2,565,000	$ 2,318,000	$ (180,000)	$ 426,000	$ 1,000	$ 6,882,000	$ 1,588,000	$ 0	$ 4,990,000	$ (1,639,000)	$ 1,943,000		$ 645,000	$ 1,294,000	$ 1,939,000
Net income	2,563,000			2,563,000				1,972,000	1,972,000				324,000			324,000		337,000				337,000		147,000	147,000		147,000
Net income on common stock	2,563,000												320,000											134,000
Long-term incentive plan activity		1,380
Employee stock purchase plan issuances		644
Appropriation of retained earnings for future dividends																		0				(337,000)	337,000
Long-term incentive plan activity	60,000	$ 60,000	1,000	(1,000)
Employee stock purchase plan issuances	23,000	23,000
Common stock dividends	(1,392,000)			(1,392,000)									(224,000)			(224,000)		(310,000)					(310,000)
Distribution to members								(1,508,000)	(1,508,000)
Allocation of tax benefit from members								62,000		62,000
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes								3,000
Allocation of tax benefit from parent													43,000	43,000				2,000			2,000
Preferred security dividends													(4,000)			(4,000)								13,000	13,000		13,000
Repayment of receivable from parent													180,000		180,000
Acquisition of Exelon Wind	3,000					$ 3,000						3,000
Other comprehensive income (loss), net of tax	(334,000)				(334,000)			(144,000)			(144,000)		(1,000)				(1,000)	(1,000)		(1,000)
Sale of noncontrolling interest																								(18,000)				(18,000)
Ending Balance at Dec. 31, 2010								7,177,000	2,633,000	3,526,000	1,013,000	5,000
Ending Balance at Dec. 31, 2010	13,563,000	$ 9,006,000	(2,327,000)	9,304,000	(2,423,000)	3,000																		2,263,000				0	190,000
Ending Balance at Dec. 31, 2010		696,589
Ending Balance at Dec. 31, 2010													2,883,000	2,361,000	0	522,000	0	6,910,000	1,588,000	(1,000)	4,992,000	(1,639,000)	1,970,000		779,000	1,294,000	2,073,000
Net income	2,499,000			2,495,000			$ 4,000	1,771,000	1,771,000				389,000			389,000		416,000				416,000		136,000	136,000		136,000
Net income on common stock	2,495,000												385,000											123,000
Long-term incentive plan activity		861
Employee stock purchase plan issuances		662
Appropriation of retained earnings for future dividends																		0				(416,000)	416,000
Long-term incentive plan activity	76,000	$ 76,000	0	0
Employee stock purchase plan issuances	25,000	25,000
Common stock dividends	(1,744,000)			(1,744,000)									(348,000)			(348,000)		(300,000)					(300,000)	(85,000)	(85,000)		(85,000)
Contribution from parent																								0
Distribution to members								(172,000)	(172,000)
Allocation of tax benefit from members								30,000		30,000
Allocation of tax benefit from parent													18,000	18,000				11,000			11,000
Preferred security dividends	4,000						4,000						(4,000)			(4,000)								(13,000)	(13,000)		(13,000)
Repayment of receivable from parent													0		0
Acquisition of Exelon Wind	0
Other comprehensive income (loss), net of tax	(27,000)				(27,000)			(98,000)			(98,000)		0				0	0		0
Ending Balance at Dec. 31, 2011								8,708,000	4,232,000	3,556,000	915,000	5,000
Ending Balance at Dec. 31, 2011	14,388,000	$ 9,107,000	(2,327,000)	10,055,000	(2,450,000)	3,000																		2,301,000				0	190,000
Ending Balance at Dec. 31, 2011		698,112
Ending Balance at Dec. 31, 2011	14,385,000												2,938,000	2,379,000	0	559,000	0	7,037,000	1,588,000	(1,000)	5,003,000	(1,639,000)	2,086,000	2,111,000	817,000	1,294,000	2,111,000
Net income	1,171,000			1,160,000		(3,000)	14,000	558,000	562,000				381,000			381,000		379,000				379,000		4,000	4,000		4,000
Net income on common stock	$ 1,160,000												377,000											(9,000)
Long-term incentive plan activity		2,432
Employee stock purchase plan issuances	857
Appropriation of retained earnings for future dividends																		0				(379,000)	379,000
Long-term incentive plan activity	$ 126,000	$ 126,000	0	0
Employee stock purchase plan issuances	26,000	26,000
Common stock dividends	$ (1,322,000)			(1,322,000)									(343,000)			(343,000)		(105,000)					(105,000)
Common stock issuance - Constellation merger - Shares	188,124
Common stock issuance - Constellation merger - Value	$ 7,365,000	7,365,000						5,264,000		5,264,000
Contribution from parent																								66,000		66,000	66,000
Distribution to members								(1,626,000)	(1,626,000)
Allocation of tax benefit from members								48,000		48,000
Allocation of tax benefit from parent													9,000	9,000				11,000			11,000
BGE preference stock acquired	193,000						193,000
Preferred security dividends	14,000						14,000						(4,000)			(4,000)								(13,000)	(13,000)		(13,000)
Repayment of receivable from parent													0		0
Acquisition of Exelon Wind								115,000		8,000		107,000
Noncontrolling interest acquired	114,000	8,000				106,000
Other comprehensive income (loss), net of tax	(317,000)				(317,000)			(402,000)			(402,000)		1,000				1,000	1,000		1,000
Noncontrolling interest in income of consolidated entity												(4,000)
Ending Balance at Dec. 31, 2012							$ 193,000	$ 12,665,000	$ 3,168,000	$ 8,876,000	$ 513,000	$ 108,000
Ending Balance at Dec. 31, 2012	21,730,000	$ 16,632,000	$ (2,327,000)	$ 9,893,000	$ (2,767,000)	$ 106,000																		2,358,000				$ 0	$ 190,000
Ending Balance at Dec. 31, 2012		889,525
Ending Balance at Dec. 31, 2012	$ 21,431,000												$ 2,982,000	$ 2,388,000	$ 0	$ 593,000	$ 1,000	$ 7,323,000	$ 1,588,000	$ 0	$ 5,014,000	$ (1,639,000)	$ 2,360,000	$ 2,168,000	$ 808,000	$ 1,360,000	$ 2,168,000

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accumulated Other Comprehensive (Loss) Income, Net
Other comprehensive income, income taxes	$ (192,000)	$ (41,000)	$ (221,000)
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	(261,000)	(64,000)	(102,000)
PECO Energy Co [Member]
Other comprehensive income, income taxes	1,000	0	(1,000)
Commonwealth Edison Co [Member]
Other comprehensive income, income taxes	$ 0	$ 0	$ 3,000

- Definition

Tax effect of other comprehensive income (loss) attributable to both parent entity and noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e640-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=18498875&loc=d3e39076-109324

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 36
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 24
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(3)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

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

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies [Abstract]

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

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

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

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

The energy generation business includes:

Generation: The integrated business consists of owned and contracted generation and investments in electric generating facilities that are marketed through its leading customer facing activities. The customer facing activities include wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and investments in natural gas exploration and production activities.

The energy delivery businesses include:
ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.

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

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

Exelon did not apply push-down accounting to BGE. As a result, BGE continues to maintain its reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and December 31, 2011. However, for Exelon's consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2012.

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

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

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, PECO, of which Exelon owns 100% of the common stock but none of PECO's preferred securities and BGE, of which Exelon owns 100% of the common stock but none of BGE's preference stock. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2012 and December 31, 2011, as equity, PECO's preferred securities as preferred securities of subsidiary, and BGE's preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for a retail power supply VIE for which Generation has no ownership interest but does have a controlling financial interest through contractual arrangements; Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon's consolidated financial statements; and certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in noncontrolling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the Noncontrolling members for certain of these projects.

ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2012, as equity.

Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd and PECO. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions.

For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded these correcting adjustments are not material to its results of operations or cash flows for the year ended December 31, 2012, or any prior period.

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

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

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

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

Certain prior year amounts in Exelon's, Generation's and BGE's Consolidated Statements of Cash Flows, Exelon's, Generation's, PECO's, ComEd's and BGE's Consolidated Statements of Operations and Comprehensive Income and in Exelon's, Generation's, ComEd's, PECO's and BGE'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.

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

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

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

Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Notes 3—Regulatory Matters and 5—Accounts Receivable for further information.

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

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. Premiums received and paid on option contracts are recognized as revenue or expense over the terms of the contracts. Since ComEd is entitled to full recovery of the costs of the financial swap contract with Generation in rates as settlements occur, ComEd records the fair value of the swap as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. See Note 3—Regulatory Matters for further information.

Proprietary Trading Activities. Exelon and Generation account for Generation's trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note – 10 Derivative Financial Instruments for further discussion.

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

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

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 12—Income Taxes for further information.

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

Exelon, Generation, ComEd, PECO and BGE present any tax assessed by a governmental authority that is the liability of the Registrants and is directly imposed on a revenue-producing transaction between a seller and a customer on a gross (included in revenues and costs) basis. See Note 20—Supplemental Financial Information for Generation's, ComEd's, PECO's and BGE's utility taxes that are presented on a gross basis.

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

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

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

Restricted cash and investments represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2012 and 2011, Exelon Corporate's restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, Exelon Corporate has funds restricted for merger commitments. In addition, Exelon Corporate's investments include its direct financing lease investments. As of December 31, 2012, Generation's restricted cash and investments primarily included cash at one of its consolidated variable interest entities and, as of 2011, primarily represented funds in escrow related to the acquisition of Shooting Star Wind Project, LLC and cash for payment of certain environmental liabilities. As of December 31, 2012 and 2011, ComEd's restricted cash primarily represented cash collateral held from suppliers associated with ComEd's energy and REC procurement contracts. As of December 31, 2011, PECO's restricted cash primarily represented funds from the sales of assets that were subject to PECO's mortgage indenture. As of December 31, 2012 and 2011, BGE's restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds.

Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2012 and 2011, Exelon's and Generation's NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2012, Exelon, ComEd, PECO and BGE had short-term investments in Rabbi trusts classified as noncurrent assets.

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

The allowance for uncollectible accounts reflects the Registrants' best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable agings, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. BGE estimates the allowance for uncollectible accounts on customer receivables by assigning reserve factors for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. ComEd, PECO and BGE customers' accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd's, PECO's and BGE's provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3 —Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

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

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

requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
requires an ongoing reconsideration of this assessment instead of only upon certain triggering events,
amends the events that trigger a reassessment of whether an entity is a VIE, and
requires the entity that consolidates a VIE (the primary beneficiary) to present separately on the face of its balance sheet (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

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

Exelon has presented separately on its Consolidated Balance Sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon's consolidated VIEs for which creditors do not have recourse to Exelon's general credit.
Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. Exelon has evaluated all existing entities under the new VIE accounting requirements, both those previously considered VIEs and those considered potential VIEs. Exelon's accounting for and disclosure about VIEs did not change materially as a result of these assessments.

See Note 2 – Variable Interest Entities for additional information.

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

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

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

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

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

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

All marketable securities are reported at fair value. Marketable securities held in the NDT funds and BGE's Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former AmerGen nuclear generating units, the Zion generating station and portions of the Peach Bottom nuclear generating units not subject to a regulatory agreement (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on BGE's Rabbi trust investments are included in earnings at Exelon and BGE. Unrealized gains and losses, net of tax, for ComEd's and PECO's available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd's and PECO's available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 13— Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 20—Supplemental Financial Information for additional information regarding ComEd's and PECO's regulatory assets and liabilities.

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

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

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

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

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

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

See Note 6—Property, Plant and Equipment, Note 7—Jointly Owned Electric Utility Plant and Note 20—Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. The estimated disposal cost of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed to operating and maintenance expense as incurred based upon the nature of the costs. A portion of the storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed.

Nuclear Outage Costs (Exelon and Generation)

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

New Site Development Costs (Exelon and Generation)

New site development costs represent the costs incurred in the assessment, design and construction of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management's determination that the project is economically and operationally feasible, management and/or the Exelon Board of Directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Upon commencement of construction, these costs will be charged to construction work in progress. Capitalized development costs are charged to operating and maintenance expense when project completion is no longer probable. At December 31, 2012 and 2011, Exelon's and Generation's capitalized development costs totaled approximately $1.2 billion and $376 million, respectively, which are included in Property, Plant and Equipment on Exelon's and Generation's Consolidated Balance Sheets. Costs included in the balance as of December 31, 2012 primarily relate to the development of the Antelope Valley project along with other, smaller renewable energy projects. See Note 4 - Merger and Acquisitions for additional information on Antelope Valley. Costs included in the balance as of December 31, 2011 primarily relate to land rights and other third-party costs directly associated with the development of certain Exelon Wind projects. Approximately $4 million, $2 million and $6 million of costs were expensed by Exelon and Generation for the years ended December 31, 2012, 2011 and 2010, respectively. These costs primarily related to the possible development of new renewable energy projects.

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

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

Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	499	$	143	$	105	$	63	$	157
December 31, 2011		280		82		120		67		62

Amortization of capitalized software costs	Exelon ^(a)		Generation^(a)		ComEd		PECO		BGE ^(a)

2012	$	208	$	81	$	56	$	30	$	32
2011		122		41		50		25		25
2010		104		33		41		19		26

__________

(a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010.

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

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

See Note 6—Property, Plant and Equipment for further information regarding depreciation.

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

Amortization of regulatory assets is recorded over the recovery period specified in the related legislation or regulatory agreement and is included in depreciation and amortization expense on ComEd's, PECO's and BGE's Consolidated Statements of Operations and Comprehensive Income.

See Note 3—Regulatory Matters and 20—Supplemental Financial Information for additional information regarding Generation's nuclear fuel, Generation's ARC and the amortization of ComEd's, PECO's and BGE's regulatory assets.

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

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years. The liabilities associated with Exelon's non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd's and PECO's accretion, through an increase to regulatory assets. See Note 13—Asset Retirement Obligations for additional information.

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

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

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

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

		Exelon^(a)		Generation ^(a)		ComEd		PECO		BGE^(a)

2012	Total incurred interest^(b)	$	1,003	$	368	$	310	$	125	$	149
	Capitalized interest		67		67		—		—		—
	Credits to AFUDC debt and equity		25		—		9		6		15

2011	Total incurred interest^(b)	$	783	$	219	$	349	$	138	$	136
	Capitalized interest		49		49		—		—		—
	Credits to AFUDC debt and equity		25		—		12		13		22

2010	Total incurred interest^(b)	$	861	$	191	$	388	$	197	$	137
	Capitalized interest		38		38		—		—		—
	Credits to AFUDC debt and equity		16		—		5		11		16

__________

(b) Includes interest expense to affiliates.

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

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

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 19—Commitments and Contingencies for additional information.

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

Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Cash flows from Generation plant assets are evaluated at a regional portfolio level along with cash flows generated from Generation's supply and risk management activities, including cash flows from contracts that are recorded as intangible contract assets and liabilities on the balance sheet. For ComEd, PECO, and BGE, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity provided. For ComEd, the lowest level of independent cash flows is transmission and distribution and, for PECO and BGE, the lowest level of independent cash flows is transmission, distribution and gas.

An impairment loss is recorded if the undiscounted expected future cash flows are less than the carrying amount of the long-lived asset or asset group. The amount of the impairment loss recorded is the difference between the estimated fair value of the long-lived asset or asset group and the carrying value.

Conditions that could have an adverse impact on the expected future cash flows and the fair value of the long-lived assets and asset groups include, among other factors, a deteriorating business climate, including current energy and market conditions, revisions to regulatory laws, or plans to dispose of a long-lived asset significantly before the end of its useful life.

Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 8—Intangible Assets for additional information regarding Exelon's and ComEd's goodwill.

Equity Method Investments. Exelon and Generation evaluate equity method investments to determine whether or not they are impaired. An impairment must be recorded when the investment has experienced an other than temporary decline in value. Additionally, if the project in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other than temporary decline in value. Exelon and Generation continuously monitor issues that potentially could impact future profitability of the equity method investments.

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

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

For derivative commodity contracts, effective with the date of the merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be 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 derivatives executed to hedge economic risk for commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company.

Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the applicable requirements, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings at Generation or offset by a regulatory asset or liability at ComEd, PECO and BGE. See Note 10—Derivative Financial Instruments for additional information.

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

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation's defined benefit pension and other postretirement benefit plans and defined contribution savings plans.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14—Retirement Benefits for additional discussion of Exelon's accounting for retirement benefits.

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

Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, including Generation's 50.01% interest in CENG, in equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment. See Note 22—Related Party Transactions for additional discussion of Exelon's and Generation's investment in CENG.

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

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

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

Fair Value Measurement

In May 2011, the FASB issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The new guidance does not impact the fair value measurements included in the Registrant's Consolidated Financial Statements as of December 31, 2012. The guidance was effective for the Registrants beginning with the period ended March 31, 2012 and was required to be applied prospectively. The Company updated the existing fair value disclosures during the first quarter of 2012 to comply with the new requirements for this standard. See Note 9 – Fair Value of Financial Assets and Liabilities for new disclosures.

Statement of Comprehensive Income

In June 2011, the FASB issued authoritative guidance requiring entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income. This guidance became effective for the Registrants for periods beginning after December 15, 2011 and was required to be applied retroactively. Each of the Registrants currently presents a single statement of comprehensive income, consistent with the new guidance.

Presentation of Items Reclassified out of Accumulated Other Comprehensive Income

In February 2013, the FASB issued authoritative guidance requiring entities to present either in the notes or parenthetically on the face of the financial statements, reclassifications from each component of accumulated other comprehensive income and the impacted income statement line items. Entities only need to disclose the impacted income statement line item for components reclassified to net income in their entirety; otherwise, a cross-reference to the related note should be provided. This guidance is effective for the Registrants for periods beginning after December 15, 2012 and is required to be applied prospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Registrants' results of operations, cash flows or financial positions.

Disclosures About Offsetting Assets and Liabilities

In December 2011 (and amended in January 2013), the FASB issued authoritative guidance requiring entities to disclose both gross and net information about recognized derivative instruments, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing or lending transactions that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. This guidance is effective for the Registrants for periods beginning on or after January 1, 2013 and is required to be applied retrospectively. This guidance is primarily applicable to certain derivative transactions for Exelon and Generation. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Registrants' results of operations, cash flows or financial positions.

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.
These items represent amounts on Generation's and Exelon's balance sheet related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $614 million and $734 million as of December 31, 2012 and December 31, 2011, respectively; offset by payables to ZionSolutions LLC of $564 million and $691 million as of December 31, 2012 and December 31, 2011, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 – Asset Retirement Obligations for further discussion.

Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these variable interest entities.

Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sells power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation is not required.

ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 13 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required.

Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 19 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required.

For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required.

ComEd, PECO and BGE

ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 19 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required.

For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs generally represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2012, the total amount of accounts payable owed by the utilities under agreements with VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in any VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements.

PECO

PETT, a financing trust, was created in 1998 by PECO to purchase and own intangible transition property (ITP) and to issue transition bonds to securitize $5 billion of PECO's stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PETT was consolidated in Exelon's and PECO's financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective on that date. Under the guidance, PECO concluded that it was the primary beneficiary of PETT due to PECO's involvement in the design of PETT, its role as servicer, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT's other expenses. The consolidation of PETT did not have a significant impact on PECO's results of operations or statement of cash flows. Upon retirement of the outstanding transition bonds on September 1, 2010, the remaining cash balance was remitted to PECO, and PETT was dissolved on September 20, 2010.

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

12 Months Ended

Dec. 31, 2012

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities Disclosure [Text Block]

2. 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 impact the entity's economic performance.

As of December 31, 2012, the Registrant's consolidated five VIEs or VIE groups for which the Registrants were the primary beneficiary, and the Registrants had significant interests in nine other VIEs for which the Registrants do not have the power to direct the entities' activities and, accordingly, were not the primary beneficiary.

Consolidated Variable Interest Entities

The carrying amounts and classification of the consolidated VIEs' assets and liabilities included in the Registrants' consolidated financial statements at December 31, 2012 and 2011 are as follows:

		December 31, 2012						December 31, 2011
		Exelon (a)		Generation		BGE (b)		Exelon		Generation		BGE (b)
Current assets		$	550	$	519	$	30	$	15	$	15	$	30
Noncurrent assets			1,802		1,762		-		784		784		-
	Total assets	$	2,352	$	2,281	$	30	$	799	$	799	$	30

Current liabilities		$	685	$	613	$	71	$	181	$	181	$	69
Noncurrent liabilities			837		532		265		77		77		332
	Total liabilities	$	1,522	$	1,145	$	336	$	258	$	258	$	401

Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the preceding table can only be settled using VIE resources.

RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. BGE determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidated BondCo.

BondCo's assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2012, 2011, and 2010, BGE remitted $85 million, $92 million, and $90 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during 2012 or 2011. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third party gas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group's activities without the additional credit support that is provided in the form of a parental guarantee. Generation is the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE.

The third party gas supply arrangement is collateralized as follows:

The assets of the retail gas entity group must be used to settle obligations under the third party gas supply agreement before it can make any distributions to Generation,
The third party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
As of December 31, 2012, Exelon provided a $75 million parental guarantee to the third party gas supplier in support of the retail gas entity group.

Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide additional financial support under the collateralized third party gas supply agreement. The third party gas supply creditors do not have any recourse to Exelon's or Generation's general credit other than the parental guarantee.

Retail Power Supply Entity. Generation also consolidates a retail power supply VIE for which Constellation became the primary beneficiary in 2008 as a result of a modification to its contractual arrangements that changed the allocation of the economic risks and rewards of the VIE among the variable interest holders. This entity now sits under Generation Consolidated and the consolidation of this VIE did not have a material impact on Generation's financial results or financial condition.

Solar Project Entity Group. In 2011, Constellation formed a group of solar project limited liability companies to build, own, and operate solar power facilities which are now part of Generation. Additionally, on September 30, 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project in northern Los Angeles County, California, from First Solar Inc. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. Generation provides capital funding to these solar VIE entities for ongoing construction of the solar power facilities. In addition, these solar VIE entities have an aggregate amount of debt with third parties of $220 million for which the creditors have recourse to Generation.

Wind Project Entity Group. Generation owns and operates a number of wind project limited liability entities, the majority of which were acquired on December 9, 2010 when Generation completed the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownership structures and risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have noncontrolling interest holders that absorb variability from the wind projects, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind power facilities. While Generation owns 100% of the majority of the wind project entities, 10 of the projects have noncontrolling equity interests held by third parties, that currently range between 1% and 6%. Of these 10 projects, Generation's current economic interests in nine of the projects are significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the non-controlling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the non-controlling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current economic interests in the projects that currently range between 94% and 99%. However, no additional support to these projects beyond what was contractually required has been provided during 2012. As of December 31, 2012, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relate to the wind generating assets, PPA intangible assets and working capital amounts.

Unconsolidated Variable Interest Entities

Exelon's and Generation's variable interests in unconsolidated VIEs generally include three transaction types: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. For the equity method investments, the carrying amount of the investments is reflected on their Consolidated Balance Sheets in investments in affiliates. 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 or guaranteed the debt or equity support, or provided liquidity arrangements, performance guarantees or other commitments associated with these commercial agreements.

As of December 31, 2012, Exelon and Generation did have significant variable interests in and exposure to loss associated with nine VIEs for which they were not the primary beneficiary; including certain equity method investments and certain commercial agreements. As of December 31, 2011, Exelon and Generation had a significant variable interest in and exposure to loss associated with one VIE for which they were not the primary beneficiary. The following tables present summary information about the significant unconsolidated VIE entities for which Exelon and Generation have exposure to loss:

				Equity
		Commercial		Method
		Agreement		Investment
December 31, 2012		VIEs		VIEs		Total
Total assets (a)		$	386	$	354	$	740
Total liabilities (a)			219		114		333
Registrants' ownership interest (a)			0		97		97
Other ownership interests (a)			167		143		310
Registrants' maximum exposure to loss:
	Letters of credit		5		0		5
	Carrying amount of equity method investments		0		77		77
	Contract intangible asset		8		0		8
	Debt and payment guarantees		0		5		5
	Net assets pledged for Zion Station decommissioning (b)		50		0		50

				Equity
		Commercial		Method
		Agreement		Investment
December 31, 2011		VIEs		VIEs		Total
Registrants' maximum exposure to loss:
	Net assets pledged for Zion Station decommissioning (b)		43		0		43

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

12 Months Ended

Dec. 31, 2012

New Accounting Pronouncements And Changes In Accounting Principles Abstract

Schedule Of New Accounting Pronouncements And Changes In Accounting Principles [Text Block]

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

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

Fair Value Measurement

Statement of Comprehensive Income

Presentation of Items Reclassified out of Accumulated Other Comprehensive Income

Disclosures About Offsetting Assets and Liabilities

- Definition

Tabular disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6801783&loc=d3e22580-107794

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6372559&loc=d3e765-108305

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6801783&loc=d3e22583-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=6958853&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6801783&loc=d3e22499-107794

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 154
-Paragraph 2, 17, 18
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 01
-Paragraph b
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-Article 10

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 28
-Paragraph 23, 24
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Regulatory Matters (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Regulatory Matters [Abstract]

Regulatory Matters (Exelon, Generation, ComEd and PECO)

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

The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd).

Background

EIMA provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. EIMA allows the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC. ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million, the first of which was made on December 31, 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates. These contributions also began in 2012.

Formula Rate Tariff

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June 2012. On May 29, 2012, the ICC issued an Order (May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC's determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd's pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a total reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for 2011 and for the first three months of 2012 consistent with the terms of the May Order.

On June 22, 2012, the ICC granted an expedited rehearing on some of the issues raised by the May Order, including ComEd's pension asset recovery. On October 3, 2012, the ICC issued its final order (Rehearing Order) in that rehearing, adopting ComEd's position on the return on its pension asset, resulting in an increase in ComEd's annual revenue requirement. In two other areas, the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in ComEd's reconciliation revenue requirement; and amending its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed an appeal of the May Order and the Rehearing Order in court on October 4, 2012. In the fourth quarter of 2012 ComEd recorded an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order, of which $75 million pre-tax reflects the reinstatement of the 2011 return on pension asset and $60 million pre-tax reflects the return on pension asset costs for 2012. New rates reflecting the impacts of the Rehearing Order went into effect in November 2012.

Capital Investment

On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under that plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd's historical level of capital expenditures. The filing with the ICC specifically included ComEd's $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. On June 22, 2012, the ICC approved the AMI Deployment Plan with certain modifications. However, as a result of the Rehearing Order above, ComEd is delaying certain elements of the AMI Deployment Plan, including the installation of additional smart meters. ComEd outlined the new deployment schedule within testimony provided in the AMI Plan Rehearing on October 3, 2012. As a result of the Rehearing Order, ComEd has deferred approximately $50 million of the 2012 AMI Deployment Plan and $15 million of 2012 planned capital investment to future years. On December 5, 2012, the ICC approved ComEd's revised AMI deployment plan. Under the AMI deployment schedule, ComEd will be taking meters out of service prior to the end of their original service lives, which resulted in recording accelerated depreciation for the remaining carrying value of the meters. The Order provides for full recovery of the cost of these early retired meters and, therefore, ComEd recorded a regulatory asset of $7 million for the accelerated depreciation of these meters in the fourth quarter of 2012.

Annual Reconciliation

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd's actual 2011 costs incurred. The ICC's final order, issued on December 20, 2012, increased the revenue requirement by $73 million, in conformity with the formula rate structure provided in the May and Rehearing Orders. The rates took effect in January 2013. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of December 31, 2012, and December 31, 2011, ComEd recorded a net regulatory asset of $209 million and $84 million, respectively, reflecting ComEd's best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred, consistent with the ICC's approved distribution formula rate structure per the May and Rehearing Orders.

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 (the same position ComEd took in its 2010 electric distribution rate case (2010 Rate Case) discussed below). 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 Rate Case became effective. In August 2011, ComEd filed testimony in the remand proceeding that no refunds should be required. The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order on remand in the proceeding 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.

ComEd has recognized for accounting purposes its best estimate of any refund obligation, as discussed above.

Advanced Metering Program Proceeding (Exelon and ComEd) In October 2009, the ICC approved a modified version of ComEd's system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC's order on Rider AMP. In ComEd's 2010 electric distribution rate case, the ICC approved ComEd's transfer of other costs from recovery under Rider AMP to recovery through electric distribution rates. On March 19, 2012, the Court reversed the ICC's approval of Rider AMP, concluding that the ICC's October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. The Illinois Supreme Court denied the Petition on September 26, 2012, and returned the matter to the ICC to calculate a refund amount. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court's order on March 19, 2012, and should not have a material impact on ComEd and Exelon.

2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its annual delivery services revenue requirement. This request was subsequently reduced to $343 million to account for changes in tax law, corrections, acceptance of limited adjustments proposed by certain parties and the amounts expected to be recovered in the AMI pilot program tariff discussed above. The request to increase the annual revenue requirement was to allow ComEd to recover the costs of substantial investments made since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and OPEB, since ComEd's rates were last determined. The original requested rate of return on common equity was 11.5%. In addition, ComEd requested future recovery of certain amounts that were previously recorded as expense that would allow ComEd to recognize a one-time benefit of up to $40 million (pre-tax). The requested increase also included $22 million for increased uncollectible accounts expense, which would increase the threshold for determining over/under recoveries under ComEd's uncollectible accounts tariff.

On May 24, 2011, the ICC issued an order in ComEd's 2010 rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd's annual delivery services revenue requirement and a 10.5% rate of return on common equity. As expected, the ICC followed the Court's position on the post-test year accumulated depreciation issue. The order allowed ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets, which is reflected as a reduction in operating and maintenance expense and income tax expense for the year ended December 31, 2012. The order also affirmed the current regulatory asset for severance costs, which was challenged by an intervener in the 2010 Rate Case. The order has been appealed to the Court by several parties. ComEd cannot predict the result of these appeals.

Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). In November 2008, the Illinois Public Utilities Act was amended to require ComEd to file tariffs establishing Utility Consolidated Billing and Purchase of Receivables services. On December 15, 2010, the ICC approved ComEd's tariff offering Purchase of Receivables with Consolidated Billing (PORCB) services for RES. Since the first quarter of 2011, ComEd has been required to buy certain RES receivables, primarily residential and small commercial and industrial customers, at the option of the RES, for electric supply service and then include those amounts on ComEd's bill to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible accounts. ComEd produces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. As of December 31, 2012, the balance of purchased accounts receivable associated with PORCB was $55 million. Under the tariff, ComEd recovers from RES and customers the costs for implementing and operating the program. A number of municipalities, including the City of Chicago, have announced their intention to switch to RES electric supply as a result of referenda voted on in November 2012. The City of Chicago switching will occur in the first quarter of 2013. The other municipalities are expected to switch during the first half of 2013. As a result, ComEd expects a significant increase in the amount of RES receivables it will be required to purchase in 2013.

Recovery of Uncollectible Accounts (Exelon and ComEd). On February 2, 2010, the ICC issued an order adopting tariffs for ComEd to recover from or refund to customers the difference between the utility's annual uncollectible accounts expense and amounts collected in rates annually. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund, which is used to assist low-income residential customers.

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, under 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. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. On February 17, 2012, the ICC approved the IPA's procurement plan covering the period June 2012 through May 2017. As of December 31, 2012, ComEd had completed the ICC-approved procurement process for its energy requirements through May 2013 as well as a portion of its requirements for each of the procurement periods ending in May 2014 and May 2015.

EIMA discussed above contains a provision for the IPA to conduct procurement events for energy and REC requirements for the June 2013 through December 2017 period. The procurement events mandated under EIMA were completed during February 2012.

The Illinois Settlement Legislation discussed below requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. The long-term renewables purchased will count towards satisfying ComEd's obligation under the state's RPS and all associated costs will be recoverable from customers. As of December 31, 2012, ComEd has completed the ICC-approved procurement process for RECs through May 2013. See Note 10 – Derivative Financial Instruments for additional information regarding ComEd's financial swap contract with Generation and long-term renewable energy contracts.

On December 19, 2012, the ICC issued an order directing ComEd and Ameren (the Utilities) to enter into sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The proposed term of the agreement is 20 years. The development was approved by the DOE on February 4, 2013. The sourcing agreement is currently being drafted and approved under a separate proceeding, with a final order expected in 2013. The sourcing agreement is expected to stipulate that the Utilities will pay (or receive) the difference between FutureGen's contract prices and the revenues FutureGen receives for capacity and energy from bidding the unit into the MISO markets. The order also directs the Utilities to recover (or pass along) the difference from the Utilities' distribution system customers, regardless of whether they purchase electricity from the Utility or from an alternative electric generation supplier. On January 22, 2013, ComEd filed an application for rehearing, requesting the ICC reconsider its December order by expanding the parties to the sourcing agreement to also include RES suppliers. On January 29, 2013, the ICC denied ComEd's rehearing request. Depending on the precise terms of the sourcing agreement, the eventual market conditions, and the manner of cost recovery, the sourcing agreement could have a material adverse impact on Exelon's and ComEd's cash flows and financial positions.

On December 19, 2012, the ICC approved the IPA's 2013 procurement plan. In response to the increased number of ComEd's customers purchasing their energy from alternative energy suppliers on their own or through municipal aggregation, the plan does not propose any new REC procurements for the period June 2013 – May 2014. Additionally, the IPA plan provides that curtailment of the existing long-term contracts for renewable energy and RECs be considered. The ICC concluded that the magnitude of this curtailment shall be determined based upon the March 2013 forecast update and that any such reduction shall be applied proportionately to each of the long-term contracts consistent with the terms of the contracts on an equal, pro-rata basis.

Illinois Settlement Legislation (Exelon, Generation and ComEd). The Illinois Settlement Legislation was signed into law in August 2007 following a settlement resulting from extensive discussions with legislative leaders in Illinois, ComEd, Generation and other utilities and generators in Illinois to address concerns about higher electric bills without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Various Illinois electric utilities, their affiliates and generators of electricity agreed to contribute approximately $1 billion over a period of four years that ended in 2010 to programs to provide rate relief to Illinois electricity customers and funding for the IPA. ComEd committed to issue $64 million in rate relief credits to customers or to fund various programs to assist customers. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, approximately $308 million for rate relief programs for customers of other Illinois utilities and approximately $5 million for partially funding operations of the IPA. The contributions were recognized in the financial statements of Generation and ComEd as rate relief credits were applied to customer bills by ComEd and other Illinois utilities or as operating expenses associated with the programs were incurred. As of December 31, 2010, Generation and ComEd had fulfilled their commitments under the Illinois Settlement Legislation.

During 2010, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement Legislation in their Consolidated Statements of Operations as follows:

		Generation		ComEd		Total Credits Issued to ComEd Customers
Year Ended December 31, 2010		Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers(a)	$	14	$	1	$	15
Credits to other Illinois utilities’ customers(a)		7		n/a		n/a
Total incurred costs	$	21	$	1	$	15

(a) Recorded as a reduction in operating revenues.

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). As a result of the Illinois Settlement Legislation, electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which increases annually to 2.0% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten-year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In February 2008, the ICC issued an order approving substantially all of ComEd's initial three-year Energy Efficiency and Demand Response Plan, including cost recovery, covering the period from June 2008 through May 2011. In December 2010, the ICC approved ComEd's second three-year Energy Efficiency and Demand Response Plan covering the period June 2011 through May 2014. The plans are designed to meet the Illinois Settlement Legislation's energy efficiency and demand response goals through May 2014, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.

Since June 1, 2008, utilities have been required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. As of December 31, 2012, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates. See Note 19 — Commitments and Contingencies for information regarding ComEd's future commitments for the procurement of RECs.

Pennsylvania Regulatory Matters

2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO's electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs on a full and current basis through a rider. The approved electric and natural gas distribution rates became effective on January 1, 2011.

In addition, the settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from the application of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The expected total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 is $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012.

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2013. PECO currently anticipates that the IRS will issue guidance in 2013 providing a safe harbor method of accounting for gas transmission and distribution property.

The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution rate cases. See Note 12 for additional information.

The 2010 electric and natural gas distribution rate case settlements did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. PECO has not filed a transmission rate case since rates have been unbundled.

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO's current PAPUC approved DSP Program, under which PECO is providing default electric service, has a 29-month term that began on January 1, 2011 and ends May 31, 2013. On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129. Under the DSP Programs, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. In addition, PECO's second DSP Program provides for the recovery of AEPS compliance costs through the GSA rather than a separate AEPS rider. The filing and implementation costs of the current and second DSP Programs were recorded as regulatory assets and are being recovered through the GSA over the DSP Programs 29-month and 24-month terms, respectively.

During 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its last three competitive procurements under the DSP Program for electric supply for default electric service. 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 the second DSP Program, PECO will procure electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes will be served through competitively procured fixed price, full requirements contracts of two years or less. Similar to the current DSP Program, for the large commercial and industrial class load, PECO will competitively procure 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 and small and medium commercial classes beginning in June 2013.

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 allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 1, 2014. PECO expects to file its plan for CAP customers by May 1, 2013.

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 included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On January 18, 2013, PECO filed with the PAPUC its universal deployment plan for approval of its proposal to deploy the remainder 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 before considering the DOE reimbursements discussed below. As of December 31, 2012, PECO has spent $241 million and $100 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 December 31, 2012, PECO has received $144 million of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $17 million as of December 31, 2012, which has been recorded in other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets.

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 intends to move 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 $19 million, net of approximately $16 million of reimbursements from the DOE. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO did not seek recovery of original meter costs in the January 2013 universal deployment filing, as resolution with the vendor is still pending. In November 2012, PECO requested and received approval from the DOE that the original meters continue to be allowable costs. In addition, PECO remains eligible for the full $200 million in SGIG funds.

As of December 31, 2012, PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As a result, a regulatory asset of $17 million, representing the cost of the original meters, net of accumulated depreciation and DOE reimbursements, was recorded on Exelon's and PECO's Consolidated Balance Sheets as of December 31, 2012. If PECO later determines that the regulatory asset is no longer probable of recovery, PECO would be required to recognize a charge in earnings in the period in which that determination was made.

Energy Efficiency Programs (Exelon and PECO). PECO's PAPUC-approved Phase I EE&C Plan has a four-year term that began on June 1, 2009 and will conclude on May 31, 2013. Spending for Phase I totals more than $328 million pursuant to Act 129's EE&C reduction targets. The Phase I plan sets forth how PECO will meet the required reduction targets established by Act 129's EE&C provisions, which include 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. If PECO fails to achieve the required reductions in consumption within the stated deadline, PECO will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers.

The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report is due to the PAPUC by November 15, 2013.

On August 2, 2012, the PAPUC issued its Phase II EE&C implementation order. The order provides energy consumption reduction requirements for the second phase of Act 129's EE&C programs, which will go into effect on June 1, 2013, but defers a decision on peak demand reduction requirements until 2013. The order tentatively established PECO's three-year cumulative consumption reduction target at 2.9%. In August 2012, PECO requested an evidentiary hearing regarding the appropriateness of its 2.9% target. The target was subsequently reaffirmed by the PAPUC on December 5, 2012. In addition, on September 4, 2012, PECO filed a Petition for Reconsideration of the terms of the PAPUC's implementation order for Phase II, which was subsequently denied.

Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II plan with the PAPUC on November 1, 2012. The plan sets forth how PECO will reduce electric consumption by at least 2.9% in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO's public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company's total annual revenue as of December 31, 2006.

Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2011, following the expiration of PECO's rate cap transition period, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 and the AEPS Act.

PECO has entered into five-year and ten-year agreements with accepted bidders, including Generation, totaling 452,000 non-solar and 8,000 solar Tier I AECs annually in accordance with a PAPUC approved plan. The plan allowed PECO to bank AECs procured prior to 2011 and use the banked AECs to meet its AEPS Act obligations over two compliance years ending May 2013. The PAPUC also approved the procurement of Tier II AECs and supplemental AECs as well as the sale of excess AECs through independent third party auctions or brokers. On January 5, 2012, PECO successfully conducted a competitive procurement for 275,000 Tier II AECs to be available toward its AEPS Act obligations for its compliance years ended May 2012 and ending May 2013, which was approved by the PAPUC on January 17, 2012.

All AEPS administrative costs and costs of AECs incurred after December 31, 2010 are being recovered on a full and current basis from default service customers through a surcharge.

PECO's second DSP Program eliminated the AEPS rider. Beginning in June 2013, AEPS compliance costs will be recovered through the GSA.

Natural Gas Choice Supplier Tariff (Exelon and PECO). During 2011, the PAPUC approved PECO's tariff supplements to its Gas Choice Supplier Coordination Tariff and its Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers (NGS) set forth in the PAPUC's final rulemaking order, which became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can require to mitigate its risk related to an NGS default, as well as PECO's ability to adjust collateral when material changes in supplier creditworthiness occur. PECO has completed its creditworthiness determinations and notified affected NGSs of their new collateral levels. As a result, PECO has obtained $14 million of collateral as of December 31, 2012.

Investigation of Pennsylvania Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania's retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for development of their next default service plan. On October 12, 2012, the PAPUC approved PECO's second DSP Program, which includes several new programs to continue PECO's support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. Further, the PAPUC issued a final order on February 14, 2013, outlining its proposed end-state for default service, which included default service pricing for residential and small commercial customers based on three month full requirements contracts, full requirement contracts using hourly spot market pricing for large commercial and industrial default service customers, and the inclusion of CAP customers in the customer choice programs.

Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC's authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities' aging electric and natural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first year rates are in effect. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11. The implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing a DSIC. PECO filed its LTIIP for its Gas Operations on February 8, 2013 with the PAPUC.

Maryland Regulatory Matters

2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs are being recovered over a 5-year period that began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. 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. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE's Smart Grid program. The ultimate resolution related to this feature could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives. The project to install the smart meters began in late April 2012.

As of December 31, 2012, BGE had received $142 million in reimbursements from the DOE. As of December 31, 2012, BGE's outstanding receivable from the DOE for reimbursable costs was $15 million, which has been recorded in other accounts receivable, net on Exelon's and BGE's Consolidated Balance Sheets.

New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that the utilities pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The three Maryland utilities are required to enter into a CfD in amounts proportionate to their relative SOS load as of the date of execution. Depending on the precise terms of the CfD, the eventual market conditions, and the manner of cost recovery, the CfD could have a material adverse impact on Exelon's and BGE's results of operations, cash flows and financial positions. On April 27, 2012, a civil complaint was filed in the United States District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on federal law grounds. Among other requests for relief, the plaintiffs seek to enjoin the MDPSC from executing or otherwise putting into effect any part of its order. The MDPSC and CPV filed motions to dismiss the federal lawsuit, which were both denied by the U.S. District Court on August 3, 2012. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. That petition was subsequently transferred to the Circuit Court for Baltimore City, where similar appeals have been filed by other interested parties. All cases have now been consolidated and will be heard together by the Circuit Court for Baltimore City in the first quarter of 2013.

2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

Dividend Restrictions (Exelon and BGE). BGE pays dividends on its common stock after its Board of Directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid.

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's most recent annual formula rate update filed in May 2012 reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. The update resulted in a revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. This compares to the May 2011 updated revenue requirement of $438 million offset by a $16 million reduction related to the reconciliation of 2010 actual costs for a net revenue requirement of $422 million. The increase in the revenue requirement was primarily driven by higher depreciation, pension and operating and maintenance costs, and the absence of a one-time credit that had been included in 2010 costs. The 2012 net revenue requirement became effective June 1, 2012, and is recovered over the period extending through May 31, 2013. The regulatory liability associated with the true-up is being amortized as the associated amounts are refunded.

ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.91%, a decrease from the 9.10% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd's long-term debt outstanding. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 55%.

BGE's most recent annual formula rate update, filed in April 2012, reflects actual 2011 expenses and investments plus forecasted 2012 capital additions on a weighted basis. This update resulted in a revenue requirement of $156 million plus an additional $2 million increase related to the reconciliation of 2011 actual costs for a net revenue requirement of $158 million. This compares to the May 2011 updated net revenue requirement of $140 million. The increase in the revenue requirement is primarily driven by higher levels of capital investment and operating expenses. The 2012 net revenue requirement became effective June 1, 2012, and is recovered over the period extending through May 31, 2013. The regulatory asset associated with the 2011 revenue requirement true-up is being amortized as the associated amounts are collected from customers.

BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.43%, a decrease from the 8.96% return included in the update filed in April 2011. The decrease in return is primarily due to a reduced equity ratio and cost of debt at 2011 year-end compared to the previous year-end. BGE's formula rate includes an 11.3% rate of return on common equity for most investments included in its rate base.

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. 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 January 21, 2010, FERC issued an order establishing paper hearing procedures to supplement the record. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. A number of entities have filed requests for rehearing. 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.

On October 11, 2012, the PJM Transmission Owners filed with FERC a cost allocation for new transmission facilities asking that the new cost allocation methodology apply to all transmission approved by the PJM Board on or after February 1, 2013. The proposed methodology is a hybrid methodology that would socialize 50% of the costs of new facilities at 500kV and above and double-circuit 345kV lines, and allocate the remaining 50% to direct beneficiaries. For all other facilities, the costs would be allocated to the direct beneficiaries. On January 31, 2013, FERC issued an order stating that the transmission owner filing is interdependent with PJM's October 25, 2012 Order No. 1000 filing and thus, while FERC accepted the cost allocation for filing, it did so subject to refund, and a further order at the time FERC issues an order on PJM's Order No. 1000 Compliance Filing.

ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE's estimated commitments are as follows:

		Total		2013		2014		2015		2016		2017

ComEd	$	525	$	175	$	86	$	135	$	128	$	1
PECO		140		28		23		26		36		27
BGE		249		15		53		119		55		7

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 proceedings leading to the FERC's approval of the existing MOPR were extensive. The parties disputed numerous elements of the MOPR including: (i) the default price that should apply to bids found subject to the MOPR, (ii) the duration of the MOPR and (iii) the application of the MOPR to self-supplying capacity and state-sponsored capacity. The FERC orders approving the existing MOPR have been appealed to the Third Circuit Court of Appeals. A resolution of that appeal is not expected until sometime in 2013.

In May 2012, PJM announced the results of its capacity auction covering 2015 and 2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. Potentially, states will expand such state-sanctioned subsidy programs or other states may seek to establish similar programs. Generation believes that further revisions to the MOPR are necessary to ensure that the potential to reduce artificially capacity auction prices is appropriately limited in PJM. In late December 2012, PJM filed a new MOPR for approval at the FERC, which Exelon believes will be more effective in preventing state-sanctioned subsidy contracts from artificially reducing capacity prices. Generation was actively involved in the process through which the MOPR changes were developed, supports the changes and intends to continue to work with PJM and its stakeholders to obtain necessary approvals. On February 5, 2013, the FERC issued a letter finding that PJM's new MOPR filing is deficient and requested that PJM provide additional information on several aspects of PJM's MOPR proposal. PJM has 30 days to respond, and a FERC decision is expected within 60 days thereafter.

Market-Based Rates (Exelon, Generation, ComEd, PECO and BGE). Generation, ComEd, PECO and BGE are public utilities for purposes of the Federal Power Act and are required to obtain FERC's acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd, PECO and BGE have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds in certain instances if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

As required by FERC's regulations, as promulgated in the Order No. 697 series, Generation, ComEd, PECO and BGE have filed market power analyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates in the regions where they are selling energy and capacity under market-based rate tariffs. FERC accepted the 2008 filings on September 16, 2008, January 15, 2009 and September 2, 2009 and accepted the 2009 filings on July 28, 2009, October 26, 2009, February 23, 2010 and April 30, 2010, affirming Exelon's affiliates continued right to make sales at market-based rates. These analyses must examine historic test period data and must be updated every three years on a prescribed schedule. The most recent updated analysis for the PJM and Northeast Regions was filed in late 2010, based on 2009 historic test period data. On June 22, 2011, FERC issued an order confirming Generation's continued authority to charge market based rates, based on Generation's most recent updated analysis filed in 2010, stating that any market power concerns are adequately addressed by PJM's monitoring and mitigation programs. Similarly, on June 29, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012, and on December 23, 2011, Generation filed its updated market power analysis for the Southeast Region which the FERC accepted on October 10, 2012. On December 21, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the SPP region, and the FERC has not yet acted on this filing.

Reliability Pricing Model (Exelon, Generation and BGE). PJM's RPM auctions take place 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2016 occurred in May 2012.

License Renewals (Exelon and Generation). On April 8, 2009, the NRC issued a renewed operating license for Oyster Creek that expires in April 2029. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.

On June 30, 2011, the NRC issued the renewed operating licenses for Salem Units 1 and 2 expiring in 2036 and 2040, respectively. Exelon is a 42.59% owner of the Salem Units.

On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States District 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. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule through rulemaking no later than September 6, 2014. Generation does not expect the NRC to issue license renewals until September 2014, 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 and the Muddy Run Pumped Storage Facility Project, respectively. The FERC review process is expected to be completed by August 31, 2014, when the current Conowingo license expires.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2012 and 2011. Upon consummation of the merger, the Registrants reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of the regulated utilities.

December 31, 2012		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits	$	304	$	3,673	$	0	$	0	$	0	$	0	$	0	$	0
Deferred income taxes			14		1,382		5		62		0		1,255		9		65
AMI programs			3		70		3		10		0		29		0		31
AMI meter events			0		17		0		0		0		17		0		0
Under-recovered distribution service
	costs		18		191		18		191		0		0		0		0
Debt costs			14		68		11		62		3		6		1		9
Fair value of BGE long-term debt (a)			0		256		0		0		0		0		0		0
Fair value of BGE supply contract (b)			77		12		0		0		0		0		0		0
Severance			29		28		25		12		0		0		4		16
Asset retirement obligations			0		90		0		65		0		25		0		0
MGP remediation costs			58		232		51		197		6		33		1		2
RTO start-up costs			3		2		3		2		0		0		0		0
Under-recovered electric universal
	service fund costs		11		0		0		0		11		0		0		0
Financial swap with Generation			0		0		226		0		0		0		0		0
Renewable energy and associated
	RECs		18		49		18		49		0		0		0		0
Under-recovered energy and
	transmission costs		43		0		14		0		1		0		28		0
DSP Program costs			1		3		0		0		1		3		0		0
DSP II Program costs			1		2		0		0		1		2		0		0
Deferred storm costs			3		6		0		0		0		0		3		6
Electric generation-related
	regulatory asset		16		40		0		0		0		0		16		40
Rate stabilization deferral			67		225		0		0		0		0		67		225
Energy efficiency and demand
	response programs		56		126		0		0		0		0		56		126
Other			23		25		14		16		9		8		0		2

Total regulatory assets		$	759		6,497	$	388	$	666	$	32	$	1,378	$	185	$	522

_________________

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. See Note 4 – Merger and Acquisitions for additional information.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved regulated rates. See Note 4 – Merger and Acquisitions for additional information.

December 31, 2012		Exelon				ComEd				PECO				BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,397	$	0	$	2,037	$	0	$	360	$	0	$	0
Removal costs			97		1,406		75		1,192		0		0		22		214
Energy efficiency and demand
	response programs		131		0		43		0		88		0		0		0
Electric distribution tax repairs			20		132		0		0		20		132		0		0
Gas distribution tax repairs			8		46						8		46
Over-recovered uncollectible
	accounts		6		0		6		0		0		0		0		0
Over-recovered energy and
	transmission costs		54		0		6		0		48		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3		0		0		0
Over-recovered AEPS costs			2		0		0		0		2		0		0		0

Total regulatory liabilities		$	321	$	3,981	$	130	$	3,229	$	169	$	538	$	22	$	214

Pension and other postretirement benefits. As of December 31, 2012, Exelon recorded regulatory assets of $3,977 million related to ComEd's and BGE's portion of deferred costs associated with Exelon's pension plans and ComEd's, PECO's and BGE's portion of deferred costs associated with Exelon's other postretirement benefit plans. PECO's pension regulatory recovery is based on cash contributions and is not included in the regulatory asset balance. The regulatory asset is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses attributable to Exelon's pension and other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the merger related to BGE's portion of the deferred costs associated with legacy Constellation's pension and other postretirement benefit plans. That BGE-related regulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at the date of the merger. See Note 14 – Retirement Benefits for additional detail. No return is earned on Exelon's regulatory asset.

Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For ComEd and BGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. ComEd was granted recovery of these additional income taxes on May 24, 2011 in the ICC's 2010 Rate Case order. The recovery period for these costs is through May 31, 2014. For BGE, these additional income taxes are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC's March 2011 rate order. See Note 12—Income Taxes and Note 14—Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates.

AMI programs. For ComEd, this amount represents operating and maintenance expenses and meter costs associated with ComEd's AMI pilot program approved in the May 24, 2011, ICC order in ComEd's 2010 rate case. The recovery periods for operating and maintenance expenses and meter costs are through May 31, 2014, and January 1, 2020, respectively. In addition, ComEd recorded approximately $7 million of accelerated depreciation costs resulting from the early retirements of non-AMI meters as a regulatory asset beginning during the fourth quarter of 2012, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the meter costs. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to the PAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating and maintenance expenses. The approved plan allows for recovery of filing and implementation costs incurred through December 31, 2010 during 2011 and 2012. In addition, the approved plan provides for recovery of program costs, which includes depreciation on new equipment placed in service, beginning in January 2011 on full and current basis, which includes interest income or expense on the under or over recovery. The approved plan also provides for recovery of accelerated depreciation on PECO's non-AMI meter assets over a 10-year period ending December 31, 2020. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatory asset, and, beginning with the MDPSC's March 2011 rate order, is earning BGE's most current authorized rate of return. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an authorized rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC order requires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. Therefore, the commencement and timing of the amortization of these deferred costs is currently unknown. BGE's AMI regulatory asset excludes costs for non-AMI meters being replaced by AMI meters, as the MDPSC has ordered that the cost recovery for non-AMI meters will be considered in a future depreciation proceeding.

AMI Meter Events. This amount represents the cost value of the original smart meters, net of accumulated depreciation and DOE reimbursements, purchased for the first phase of smart meter deployment that will no longer be used, including installation and removal costs. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO has deferred these costs on Exelon's and PECO's Consolidated Balance Sheet. PECO will not earn a return on the recovery of these costs.

Under-recovered distribution services costs. Under EIMA, which became effective in the fourth quarter of 2011, ComEd is allowed recovery of distribution services costs through a formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to reflect the actual costs that the ICC determines are prudently and reasonably incurred in a given year. The reconciliation will be recovered through rates over a one-year period, beginning in January 2013 for the 2011 annual reconciliation period. The regulatory asset also includes costs associated with certain one-time events, such as large storms, which will be recovered over a five-year period beginning in January 2013. ComEd is earning a return on these costs. As of December 31, 2012, the regulatory asset was comprised of $125 million for the annual reconciliation and $84 million related to significant one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2012 balance related to significant one-time events contains $26 million of merger and integration related costs, net of amortization, incurred as a result of the merger. As of December 31, 2012, ComEd and BGE recorded regulatory assets of $5 million and $1 million, respectively, in other regulatory assets for merger and integration-related costs. See Note 4 – Mergers and Acquisitions for additional information.

Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd's, PECO's and BGE's recoverable losses on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on the recovery of these costs.

Severance. For ComEd, these costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006, ICC rehearing rate order and the May 24, 2011, ICC order in ComEd's 2010 rate case. The recovery periods are through June 30, 2014, and May 31, 2014, respectively. ComEd is not earning a return on these costs. For BGE, these costs represent deferred severance costs that BGE has either previously been granted recovery of in rates or has requested recovery in a current rate case. Costs include the portion of costs associated with a 2008 workforce reduction that relate to BGE's gas business which were deferred in 2009 as a regulatory asset in accordance with the MDPSC's orders in prior rate cases and are being amortized over a 5-year period that began in January 2009. Also included are costs associated with a 2010 workforce reduction that were deferred as a regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC's March 2011 rate order. Finally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with the MDPSC's orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on the regulatory asset included in base rates.

Asset retirement obligations. These costs represent future removal costs associated with ComEd's and PECO's existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd will recover these costs through future depreciation expense and will earn a return on these costs once the removal activities have been performed. See Note 13—Asset Retirement Obligations for additional information.

MGP remediation costs. Recovery of these items was granted to ComEd in the July 26, 2006, ICC rate order. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. These costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. BGE is earning a regulated return on the regulatory asset included in base rates. See Note 19—Commitments and Contingencies for additional information.

RTO start-up costs. Recovery of these RTO start-up costs was approved by FERC. The recovery period is through March 31, 2015. ComEd is earning a return on these costs.

Under (Over)-recovered universal service fund costs. The universal service fund cost is a recovery mechanism that allows PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2012, PECO was under-recovered for its electric program and over-recovered for its gas program. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.

Financial swap with Generation. To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap contract with Generation that expires on May 31, 2013. Since the swap contract was deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period are recorded by ComEd as well as an offsetting regulatory asset or liability. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd's cost to purchase energy on the spot market and the contracted price. In Exelon's consolidated financial statements, the fair value of the intercompany swap recorded by Generation and ComEd is eliminated.

Renewable Energy and Associated RECs. 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. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd's cost to purchase energy on the spot market and the contracted price.

Under (Over)-recovered energy and transmission costs. Starting in 2007, ComEd's energy and transmission costs are recoverable (refundable) under ComEd's ICC and/or FERC-approved rates. ComEd earns interest on under-recovered costs and pays interest on over-recovered costs to customers. The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO's GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2012, PECO had a regulatory asset related to under-recovered electric transmission costs of $1 million and a regulatory liability that included $47 million related to over-recovered electric supply costs under the GSA and $1 million related to over-recovered natural gas supply costs under the PGC. As of December 31, 2011, PECO had a regulatory asset related to under-recovered transmission costs of $9 million and a regulatory liability that included $25 million related to over-recovered electric supply costs under the GSA and $5 million related to over-recovered natural gas supply costs under the PGC. The BGE energy costs represent the electric and gas supply related costs recoverable (refundable) from (to) customers under BGE's market-based SOS and MBR programs, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. See "ITEM 1. BUSINESS - BGE" for further details on BGE's market-based SOS and MBR programs. As of December 31, 2012, BGE had a regulatory asset that included $9 million related to under-recovered electric supply costs and $19 million related to under-recovered natural gas supply costs.

DSP Program costs. These amounts represent recoverable administrative costs incurred relating to filing, procurement, and information technology improvements associated with PECO's PAPUC-approved DSP Program for the procurement of electric supply following the expiration of PECO's generation rate caps on December 31, 2010. The filing and implementation costs of this DSP Program are recoverable through the GSA over its 29-month term, beginning January 1, 2011. The independent evaluator costs associated with conducting procurements is recoverable over a 12-month period after the PAPUC approves the results of the procurements. Costs relating to information technology improvements are recoverable over a 5-year period beginning January 1, 2011. PECO earns a return on the recovery of information technology costs.

DSP II Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO's second PAPUC-approved DSP program for the procurement of electric supply. The filing and procurement of this DSP Program are recoverable through the GSA over its 24-month term, beginning June 1, 2013. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earning a return on these costs.

Deferred storm costs. In the MDPSC's March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. These costs are being amortized over a 5-year period that began in December 2010. BGE is earning a regulated return on the regulatory asset included in base rates.

Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $47 million as of December 31, 2012, and $56 million as of December 31, 2011. BGE will continue to amortize this amount through 2017.

Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006, to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007, to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2012 and 2011, BGE recovered $67 million and $57 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007.

Energy efficiency and demand response programs. These amounts represent costs recoverable (refundable) under ComEd's ICC approved Energy Efficiency and Demand Response Plan, PECO's PAPUC-approved EE&C Plan, and BGE's Smart Energy Savers Program®. ComEd began recovering these costs or refunding over-collections of these costs on June 1, 2008 through a rider. ComEd earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. PECO began recovering these costs through a rider in January 2010 based on projected spending under the program. Recovery will continue over the life of the program, which expires on May 31, 2013. Excess funds collected are required to be refunded no later than June 30, 2013. PECO earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. BGE's Smart Energy Savers Program® includes both MDPSC approved demand response and energy efficiency programs. For the BGE demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Actual costs incurred in the conservation program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a regulated rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.

Rate case costs. The ICC generally allows ComEd to receive recovery of rate case costs over three years. The ICC has issued orders allowing recovery of these costs on July 26, 2006, September 10, 2008, and May 24, 2011. The recovery period for the two former rate case costs was through September 15, 2011. The recovery period for the 2010 Rate Case costs is through May 31, 2014. Pursuant to the approved settlements of the 2010 electric and natural gas distribution rate cases, PECO is allowed recovery of rate case costs over two years ended December 31, 2012. ComEd and PECO do not earn a return on the recovery of these costs.

Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 13—Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds ComEd and BGE have received from customers to cover the future removal of property, plant and equipment which reduces rate base for ratemaking purposes.

Electric distribution tax repairs. PECO's 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. No interest will be paid to customers.

Gas distribution tax repairs. PECO's 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits will be reflected in customer bills beginning January 1, 2013. No interest will be paid to customers.

Under (Over)-recovered uncollectible accounts. As a result of the February 2010 ICC order approving recovery of ComEd's uncollectible accounts, ComEd has the ability to adjust its rates annually to reflect the increases and decreases in annual uncollectible accounts expense starting with year 2008. ComEd recorded a regulatory asset for the cumulative under-collections in 2008 and 2009. Recovery of the initial regulatory asset was completed over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. ComEd is not earning a return on these costs.

Under (Over)-recovered AEPS costs current asset (liability). The AEPS costs represent the administrative and AEC costs incurred to comply with the requirements of the AEPS Act, which are recoverable on a full and current basis. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.

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 their POR programs. Purchased billed receivables are classified in other accounts receivable, net on Exelon's, ComEd's, PECO's and BGE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of December 31, 2012 and 2011.

As of December 31, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	191	$	55	$	65	$	71
Allowance for uncollectible accounts (b)		(21)		(9)		(6)		(6)
Purchased receivables, net	$	170	$	46	$	59	$	65

As of December 31, 2011	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	68	$	16	$	52	$	61
Allowance for uncollectible accounts (b)		(5)		-		(5)		(3)
Purchased receivables, net	$	63	$	16	$	47	$	58

__________

(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, 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.

December 31, 2011		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits	$	204	$	2,794	$	0	$	0	$	7	$	0	$	3	$	0
Deferred income taxes			5		1,176		5		66		0		1,110		8		68
AMI and smart meter programs			2		28		2		6		0		22		0		15
Under-recovered distribution service
	costs		14		70		14		70		0		0		0		0
Debt costs			18		81		15		73		3		8		2		10
Severance			25		38		25		38		0		0		0		1
Asset retirement obligations			0		74		0		50		0		24		0		0
MGP remediation costs			30		129		24		91		6		38		1		2
RTO start-up costs			3		4		3		4		0		0		0		0
Under-recovered electric universal
	service fund costs		3		0		0		0		3		0		0		0
Financial swap with Generation			0		0		503		191		0		0		0		0
Renewable energy and associated
	RECs		9		97		9		97		0		0		0		0
Under-recovered energy and
	transmission costs		57		0		48		0		9		0		50		0
DSP Program costs			3		2		0		0		3		2		0		0
Deferred storm costs			0		0		0		0		0		0		3		9
Electric generation-related
	regulatory asset		0		0		0		0		0		0		16		56
Rate stabilization deferral			0		0		0		0		0		0		63		295
Energy efficiency and demand
	response programs		0		0		0		0		0		0		29		95
Other			17		25		9		13		8		12		0		0

Total regulatory assets		$	390	$	4,518	$	657	$	699	$	39	$	1,216	$	175	$	551

December 31, 2011		Exelon				ComEd				PECO				BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,222	$	0	$	1,857	$	0	$	365	$	0	$	0
Removal costs			61		1,185		61		1,185		0		0		18		200
Energy efficiency and demand
	response programs		49		69		49		0		0		69		0		0
Electric distribution tax repairs			19		151		0		0		19		151		0		0
Over-recovered uncollectible
	accounts		15		0		15		0		0		0		0		0
Over-recovered energy and
	transmission costs		42		0		12		0		30		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3		0		0		0
Over-recovered AEPS costs			8		0		0		0		8		0		0		0
Other			0		0		0		0		0		0		1		1

Total regulatory liabilities		$	197	$	3,627	$	137	$	3,042	$	60	$	585	$	19	$	201

Merger and Acquisitions (Exelon and Generation)

12 Months Ended

Dec. 31, 2012

Acquisitions [Line Items]

Acquisitions (Exelon and Generation)

4. Merger and Acquisitions

Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE)

Description of Transaction

On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation's interest in RF HoldCo LLC, which holds Constellation's interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon's interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.

Constellation's shareholders received 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock outstanding as of March 12, 2012. Generally, all outstanding Constellation equity-based compensation awards were converted into Exelon equity-based compensation awards using the same ratio. See Note 17 – Common Stock for further information.

Regulatory Matters

In December 2011, Exelon and Constellation reached a settlement with the State of Maryland and the City of Baltimore and other interested parties in connection with the regulatory proceedings related to the merger that were pending before the MDPSC. As part of this settlement and the application for approval of the merger by MDPSC, 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 more than $1 billion.

On February 17, 2012, the MDPSC approved the merger with conditions. Many of the conditions were reflective of the settlement agreements described above. The following costs were recognized after the closing of the merger and are included in Exelon's, Generation's and BGE's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012:

Description		Payment Period	BGE		Generation		Exelon		Statement of Operations Location
BGE rate credit of $100 per residential customer (a)		Q2 2012	$	113	$	0	$	113	Revenues
Customer investment fund to invest in energy efficiency
	and low-income energy assistance to BGE customers	2012 to 2014		0		0		113.5	O&M Expense
Contribution for renewable energy, energy efficiency
	or related projects in Baltimore	2012 to 2014		0		0		2	O&M Expense
Charitable contributions at $7 million per year for 10 years		2012 to 2021		28		35		70	O&M Expense
State funding for offshore wind development projects		Q2 2012		0		0		32	O&M Expense
Miscellaneous tax benefits		Q2 2012		(2)		0		(2)	Taxes Other Than Income
	Total		$	139	$	35	$	328.5

Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.

In addition to these costs, the direct investment estimate includes $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for Generation's competitive energy businesses. The construction is expected to be completed in 1 to 2 years. The estimate also includes $625 million for Exelon's and Generation's commitment to develop or assist in the development of 285 – 300 MWs of new generation in Maryland, expected to be completed over a period of 10 years. Such costs, which are expected to be primarily capital in nature, will be recognized as incurred. As of December 31, 2012, amounts reflected in the Exelon and Generation consolidated financial statements for these commitments were immaterial.

The settlement agreement 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, 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. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of December 31, 2012, it is reasonably possible that Exelon will be required to make subsidy or liquidated damages payments of approximately $40 million rather than build one of the generation projects contemplated by the commitments, given that the generation build is dependent upon the passage of legislation and other conditions that Exelon does not control.

Pursuant to the MDPSC merger approval conditions, BGE is restricted from paying any dividend on its common shares through the end of 2014, is required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and is not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process.

Associated with certain of the regulatory approvals required for the merger, Exelon and Constellation agreed to enter into contracts to sell three Constellation generating stations located in PJM within 150 days (subsequently extended 30 days by the DOJ) following the merger completion and to complete the divestitures within 30 days after receipt of regulatory approvals. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, include base-load, coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity.

On August 8, 2012, a subsidiary of Generation reached an agreement to sell these three Maryland generating stations and associated assets to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. The sale was completed on November 30, 2012. The sale agreement included a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in net proceeds from the sale of approximately $371 million. Decisions by certain market participants to remove themselves from the bidding process, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realized sales proceeds below Generation's estimated fair value of the Maryland generating stations. Consequently, Exelon and Generation recorded a pre-tax loss of $278 million in operating and maintenance expense in the third quarter of 2012 to reflect the difference between the estimated sales price at that time and carrying value. This loss amount was adjusted to $272 million to reflect the final sales price upon closing on November 30, 2012.

In connection with the sale of the Maryland generating stations, Exelon agreed to indemnify Raven Power for certain costs associated with the treatment of hazardous substances at off-site disposal facilities and any claims arising as a result of, or in connection with, any toxic tort, natural resource damages, loss of life or injury to persons due to releases of, or exposure to hazardous substances in connection with Raven Power's remediation of environmental contamination or Exelon's non-compliance with environmental laws or permits prior to the closing date of the sale.

Subsequent to the merger, Generation discovered that, for the first two weeks following the merger, due to a software error, Generation inadvertently bid certain generating units into the PJM energy market at prices that slightly exceeded the cost-based caps to which it had agreed. This error was a violation of the commitments made in connection with merger approvals by DOJ, FERC and the MDPSC. Generation reported the error to the DOJ, FERC and the MDPSC and committed to remedy the impacts of its error. The MDPSC held a hearing to review the error, and accepted Generation's proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for some minor adjustments to the cost build up for certain of its PJM units. Generation has coordinated with PJM to determine the impact on Generation's revenues and the market from this error and these adjustments, and Generation has worked with PJM to reverse the financial impacts. In November 2012, Generation reached a settlement with the DOJ regarding this matter. The final resolution did not have a material impact on Exelon's or Generation's results of operations, cash flows or financial position.

In addition, in January 2012, Exelon and Constellation reached an agreement with EDF under which EDF withdrew its opposition to the Exelon-Constellation merger. The terms of the agreement address CENG, a joint venture between Constellation and EDF that owns and operates a total of three nuclear facilities with a total of five generating units in Maryland and New York. The agreement reaffirms the terms of the joint venture. The agreement did not include any exchange of monetary consideration, and Exelon does not expect the agreement will have a material effect on Exelon's and Generation's future results of operations, financial position and cash flows.

Exelon was named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors' breaches. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. On June 26, 2012, the court approved the settlement and entered final judgment.

Accounting for the Merger Transaction

The total consideration in the merger was based on the opening price of a share of Exelon common stock on March 12, 2012 (in millions):

	Number of Shares/ Awards Issued	Total Fair Value
Issuance of Exelon common stock to Constellation shareholders and equity award holders at the exchange ratio of 0.930 shares for each share of Constellation common stock; based on the opening price of Exelon common stock on March 12, 2012 of $38.91 (a)	187.45	$	7,294
Issuance of Exelon equity awards to replace existing Constellation equity awards (b)	11.30		71
Total purchase price		$	7,365

The number of shares issued excludes 0.7 million shares of stock that are held in a custodian account specifically for the settlement of unvested share-based restricted stock awards. The related share value is excluded from the estimated fair value as these awards have not vested and, therefore, are not in the purchase price.
Includes vested Constellation stock options and restricted stock units converted at fair value to Exelon awards on March 12, 2012. The fair value of the stock options was determined using the Black-Scholes model.

All options to purchase Constellation common stock under various equity agreements were converted into options to acquire a number of shares of Exelon common stock (as adjusted for the exchange ratio) at an option price. All Constellation unvested restricted stock awards granted prior to April 28, 2011, that were outstanding immediately prior to the consummation of the Merger, became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and converted into Exelon common stock at the exchange ratio in accordance with the applicable stock plan and award agreement terms. All Constellation restricted stock awards that remained unvested on a pro rata basis pursuant to the foregoing formula, and any Constellation unvested restricted stock awards granted after April 28, 2011, have been assumed by Exelon and automatically converted into shares of unvested restricted stock of Exelon at the exchange ratio. Likewise, all restricted stock units granted prior to April 28, 2011 under the Constellation Plans and outstanding immediately prior to the completion of the Initial Merger became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and have been assumed by Exelon and automatically converted into a number of shares of Exelon common stock at the exchange ratio.

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

The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to rate-setting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE's tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE's debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE's assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1 – Significant Accounting Policies for additional information on BGE's push-down accounting treatment. Also see Note 3 – Regulatory Matters for additional information on BGE's regulatory assets.

The valuations performed in the first quarter of 2012 to assess the fair values of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2012. The allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed. The preliminary valuations performed in the first quarter of 2012 were updated in the second, third and fourth quarters of 2012, with the most significant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply and fuel contracts, unregulated property, plant and equipment and investments in affiliates. The preliminary amounts recognized are subject to further revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the merger date. Any changes to the fair value assessments may affect the purchase price allocation and material changes could require the financial statements to be retroactively amended.

The updated preliminary purchase price allocation of the Initial Merger of Exelon with Constellation and Exelon's contribution of certain subsidiaries of Constellation to Generation at December 31, 2012 was as follows:

Preliminary Purchase Price Allocation, excluding amortization	Exelon		Generation
Current assets	$	4,936	$	3,638
Property, plant and equipment		9,342		4,054
Unamortized energy contracts		3,218		3,218
Other intangibles, trade name and retail relationships		457		457
Investment in affiliates		1,942		1,942
Pension and OPEB regulatory asset		740		0
Other assets		2,265		1,266
Total assets		22,900		14,575

Current liabilities		3,408		2,804
Unamortized energy contracts		1,722		1,512
Long-term debt, including current maturities		5,632		2,972
Noncontrolling interest		90		90
Deferred credits and other liabilities and preferred securities		4,683		1,933
Total liabilities, preferred securities and noncontrolling interest		15,535		9,311
Total purchase price	$	7,365	$	5,264

Intangible Assets Recorded

For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the contracts were in or out-of-the-money. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the merger date. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. Exelon and Generation present separately in their Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. Exelon's and Generation's amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $1,098 million. This amortization expense excludes the $116 million in amortization of the regulatory asset and equally offsetting amortization of the fuel supply contract liability recorded at Exelon Corporate in the Consolidated Statement of Operations. The weighted-average amortization period is approximately 1.5 years.

The fair value of the Constellation trade name intangible asset was determined based on the relief from royalty method of the income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. Exelon's and Generation's straight line amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $20 million. The amortization period is approximately 10 years. The trade name intangible asset is included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets.

The fair value of the retail relationships was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset's fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The intangible assets are amortized as amortization expense on a straight line basis over the useful life of the underlying assets averaging approximately 12.4 years. Exelon's and Generation's amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $15 million. The retail relationships intangible assets are included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets.

Exelon's intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of December 31, 2012:

								Estimated amortization expense
Description	Weighted Average Amortization	Gross		Accumulated Amortization		Net		2013		2014		2015		2016		2017		2018 and Beyond
Unamortized energy contracts, net (a)	1.5	$	1,496	$	(982)	$	514	$	394	$	74	$	19	$	(31)	$	(22)	$	80
Trade name	10.0		243		(20)		223		24		24		24		24		24		103
Retail relationships	12.4		214		(15)		199		19		19		19		19		19		104

Total, net		$	1,953	$	(1,017)	$	936	$	437	$	117	$	62	$	12	$	21	$	287

(a) Includes the fair value of BGE's power and gas supply contracts for which an offsetting Exelon Corporate regulatory asset was also recorded.

Impact of Merger

It is impracticable to determine the current quarter and year-to-date overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation's operations and are therefore not fully distinguishable after the merger.

The impact of BGE on Exelon's Consolidated Statement of Operations and Comprehensive Income includes operating revenues of $2,091 million and net loss of $31 million during the year ended December 31, 2012.

During the year ended December 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $746 million, $340 million, $5 million, $17 million and $160 million, respectively. These amounts do not include merger and integration-related costs of $36 million and $22 million incurred at ComEd and BGE, respectively, which have been recorded as a regulatory asset. The costs incurred are classified primarily within Operating and Maintenance Expense in the Registrants' respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the BGE customer rate credit and the credit facility fees, which are included as a reduction to operating revenues and other, net, respectively, for the year ended December 31, 2012.

During the year ended December 31, 2011, Exelon, Generation and PECO incurred merger and integration-related costs of $77 million, $15 million and $2 million, respectively. These costs are classified primarily within Operating and Maintenance Expense in the Registrants' respective Consolidated Statements of Operations and Comprehensive Income.

Severance Costs

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.

Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process; as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. The amount of severance expense associated with the post-merger integration recognized through December 31, 2012, for Exelon is $138 million, which includes $88 million, $16 million, $7 million and $19 million for Generation, ComEd, PECO and BGE, respectively. Estimated costs to be incurred after December 31, 2012 are not material. In addition, certain employees identified during the staffing and selection process also receive pension and other postretirement benefits that are deemed contractual termination benefits. See Note 14 – Retirement Benefits for additional information on the contractual termination benefits.

For the year ended December 31, 2012, the Registrants recorded the following severance benefits costs associated with the identified job reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for ComEd and BGE:

Year Ended December 31, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	124	$	80	$	14	$	7	$	17
Stock compensation		7		4		1		0		1
Other charges		7		4		1		0		1
Total severance benefits	$	138	$	88	$	16	$	7	$	19

_________________

The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
ComEd established regulatory assets of $16 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.

Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:

Year Ended December 31, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2011	$	0	$	0	$	0	$	0	$	0
Severance charges (a)		124		38		2		0		11
Stock compensation		7		2		0		0		0
Other charges (b)		7		2		0		0		1
Payments		(27)		(9)		(1)		0		(1)
Balance at December 31, 2012	$	111	$	33	$	1	$	0	$	11

Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. Amounts also include one-time termination benefits of $3 million and $1 million for Exelon and Generation, respectively, which they began to recognize in the second quarter of 2012.
Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services.

Cash payments under the plan began in the second quarter of 2012. Substantially all cash payments under the plan are expected to be made by the end of 2016.

Pro-forma Impact of the Merger

The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon's and Generation's accounting policies and adjusting Constellation's, including BGE's as appropriate, results to reflect purchase accounting adjustments.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

	Generation				Exelon
		Year Ended December 31,				Year Ended December 31,
(unaudited)		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	17,013	$	19,494	$	26,700	$	30,712
Net income attributable to Exelon		1,205		324		2,092		974

Basic Earnings Per Share		n.a.		n.a.	$	2.56	$	1.15
Diluted Earnings Per Share		n.a.		n.a.		2.55		1.14

_________________

The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.
The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.

Acquisitions (Exelon and Generation)

Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future power and fuel market prices. Additionally, market prices based on the Market Price Referent (MPR) established by the CPUC for renewable energy resources were used in determining the fair value of the Antelope Valley assets acquired and liabilities assumed. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and the duration of the liabilities assumed. Generation did not record any goodwill related to any of the respective acquisitions.

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for each of the companies acquired by Generation during the years ended December 31, 2011 and December 31, 2010:

		Acquisitions
		2011				2010
		Wolf Hollow		Antelope Valley		Exelon Wind
Fair value of consideration transferred
Cash	$	305	$	75	$	893
Plus: Gain on PPA settlement		6		-		-
Contingent consideration		-		-		32

Total fair value of consideration transferred	$	311	$	75	$	925

Recognized amounts of identifiable assets acquired and liabilities assumed

Property, plant and equipment	$	347	$	15	$	700
Inventory		5		-		-
Intangible assets ^(a)		-		190		224
Payable to First Solar, Inc. ^(b)		-		(135)		-
Working capital, net		(5)		-		18
Asset retirement obligations		-		-		(13)
Noncontrolling interest		-				(3)
Other Assets		-		5		(1)

Total net identifiable assets	$	347	$	75	$	925

Bargain purchase gain	$	36	$	-	$	-

(a) See Note 8 - Intangible Assets for additional information.

(b) Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a "seller financing" arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation's implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc.

Wolf Hollow, LLC. On August 24, 2011, Generation completed the acquisition of all of the equity interests of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, for a purchase price of $311 million which increased Generation's owned capacity within the ERCOT power market by 720 MWs. The acquisition supports the Exelon commitment to renewable energy as part of Exelon 2020.

Generation recognized an approximately $36 million non-cash bargain purchase gain (i.e., negative goodwill). The gain was included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

The pro forma impact of this acquisition would not have been material to Exelon's or Generation's results of operations for the years ended December 31, 2011 and 2010.

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, which developed and will build, operate, and maintain the project. The first block began operations in December 2012, with three additional blocks coming online in February 2013 and an expectation of full commercial operation by the end of the third quarter of 2013. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant. The acquisition supports Exelon's commitment to renewable energy as part of Exelon 2020.

Exelon expects to invest up to $701 million in equity in the project through 2013. The DOE's Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the project. On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million and terminated the put option that Generation had on the Antelope Valley project. See Note 11 – Debt and Credit Agreements for additional information on the DOE loan guarantee.

The pro forma impact of this acquisition would not have been material to Exelon's or Generation's results of operations for the years ended December 31, 2011 and 2010.

Exelon Wind. On December 9, 2010, Generation paid consideration of $893 million to complete the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power. Under the terms of the agreement, Generation added 735 MWs of installed, operating wind capacity located in eight states. The acquisition supports Exelon's commitment to renewable energy as part of Exelon 2020.

The contingent consideration arrangement requires that Generation pay up to $40 million related to three individual projects with an aggregate capacity of 230 MWs, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. The fair value of the contingent consideration arrangement of $32 million was determined as of the acquisition date based upon a weighted average probability of meeting certain contractual commitments related to the commencement of construction of each project, which is considered an unobservable (Level 3) input pursuant to applicable accounting guidance. During the third quarter of 2011, $16 million of contingent consideration was paid to Deere & Company for one of the projects and the probability of a second project beginning construction, Harvest II, was increased to 100%. As a result, the contingent consideration included in other current liabilities within Exelon's and Generation's Consolidated Balance Sheets was adjusted to $10 million to reflect the full expected contingent payment related to the Harvest II project and subsequently paid to Deere & Company during the third quarter of 2012. Additionally, $2 million was recorded in operating and maintenance expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The remaining $8 million of contingent consideration is included in other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.

The fair value of the assets acquired included customer receivables of $18 million. There are no outstanding customer receivables that were acquired in the Exelon Wind transaction.

The $3 million noncontrolling interest represents the noncontrolling members' proportionate share in the fair value of the assets acquired and liabilities assumed in the transaction.

The pro forma impact of this acquisition would not have been material to Exelon's or Generation's results of operations for the year ended December 31, 2010.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1497-128463

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-Paragraph 4
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-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7488404&loc=d3e7008-128479

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-Paragraph 3
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4845-128472

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-Name Accounting Standards Codification
-Topic 805
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-Section 50
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-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1383-128463

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 88-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph F4
-Subparagraph e
-Appendix F

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51, 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 67-73
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Accounts Receivable (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Accounts Receivables [Abstract]

Accounts Receivable (Exelon, Generation, ComEd and PECO)

5. Accounts Receivable (Exelon, Generation, ComEd PECO and BGE)

Accounts receivable at December 31, 2012 and 2011 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:

2012	Exelon		Generation		ComEd		PECO			BGE

Unbilled customer revenues	$	1,418	$	859	$	213	$	164		$	182
Allowance for uncollectible accounts (a)		(293)		(84)		(70)		(99)	(b)		(40)

2011	Exelon		Generation		ComEd		PECO			BGE

Unbilled customer revenues	$	902	$	493	$	246	$	163		$	194
Allowance for uncollectible accounts (a)		(199)		(29)		(78)		(92)	(b)		(37)

(a) Includes the allowance for uncollectible accounts on customer and other accounts receivable.

(b) Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2012 and 2011, respectively, related to PECO's current installment plan receivables described below.

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 $18 million and $21 million as of December 31, 2012 and 2011, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 – Significant Accounting Policies. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2012 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2011 of $17 million consists of $1 million, $3 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of December 31, 2012 and 2011 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.

Accounts Receivable Agreement (Exelon and PECO). PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable, which is accounted for as a secured borrowing. On November 28, 2012, PECO made a principal paydown of $15 million to meet the compliance requirements for the October 2012 reporting period. The remaining principal balance of $210 million is classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets. As of December 31, 2012 and 2011, the financial institution's undivided interest in PECO's gross accounts receivable was equivalent to $289 million and $329 million, respectively, which is calculated under the terms of the agreement. See Note 11—Debt and Credit Agreements for additional information regarding the accounts receivable agreement.

- Definition

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7512638&loc=d3e5066-111524

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.3,4)
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.4-08.(k))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7512638&loc=d3e5074-111524

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 01-6
-Paragraph 13
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
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-Section 03
-Paragraph 7
-Article 9

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph k
-Article 4

+ Details

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

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

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

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

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	90	$	26,576	$	21,716
Electric—generation (a)		1	-	53		19,004		13,682
Gas—transportation and distribution		5	-	90		3,108		1,793
Common—electric and gas		5	-	50		1,029		564
Nuclear fuel (b)		1	-	8		4,815		4,225
Construction work in progress		N/A				1,926		1,110
Other property, plant and equipment (c)		3	-	72		912		439

	Total property, plant and equipment					57,370		43,529
	Less: accumulated depreciation (d)					12,184		10,959

Property, plant and equipment, net					$	45,186	$	32,570

(a) Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.

(b) Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(c) Includes Generation's buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively. Also includes land held for future use and non utility property at ComEd, PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation.

(d) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.76	%	2.59	%	2.53	%
Electric—generation	3.15	%	3.12	%	2.86	%
Gas	2.03	%	1.73	%	1.75	%
Common—electric and gas	7.61	%	8.05	%	7.25	%

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—generation (a)		1	-	53	$	19,004	$	13,682
Nuclear fuel (b)		1	-	8		4,815		4,225
Construction work in progress		N/A				1,352		827
Other property, plant and equipment (c)		5	-	57		374		54

	Total property, plant and equipment					25,545		18,788
	Less: accumulated depreciation (d)					6,014		5,313

Property, plant and equipment, net					$	19,531	$	13,475

(a) Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.

(b) Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(c) Includes buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively.

(d) Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.15%, 3.12% and 2.86% for the years ended December 31, 2012, 2011 and 2010, respectively.

License Renewals. Generation's depreciation provisions are based on the estimated useful lives of its generating stations, which assume the renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information regarding license renewals.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	75	$	16,480	$	15,637
Construction work in progress		N/A				294		187
Other property, plant and equipment (a)		72				50		47

	Total property, plant and equipment					16,824		15,871
	Less: accumulated depreciation					2,998		2,750

Property, plant and equipment, net					$	13,826	$	13,121

(a) Represents land held for future use and non utility property.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.79%, 2.67% and 2.64% for the years ended December 31, 2012, 2011 and 2010, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	65	$	6,355	$	6,079
Gas—transportation and distribution		5	-	70		1,859		1,793
Common—electric and gas		5	-	50		568		564
Construction work in progress		N/A				76		83
Other property, plant and equipment (a)			50			17		17

	Total property, plant and equipment					8,875		8,536
	Less: accumulated depreciation					2,797		2,662

Property, plant and equipment, net					$	6,078	$	5,874

(a) Represents land held for future use and non utility property.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.51	%	2.33	%	2.17	%
Gas	1.77	%	1.73	%	1.75	%
Common—electric and gas	7.54	%	8.05	%	7.25	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:

	Average Service Life
	(years)			2012		2011
Asset Category
Electric—transmission and distribution	5	-	90	$	5,767	$	5,483
Gas—transmission and distribution	5	-	90		1,548		1,387
Common—electric and gas	5	-	40		554		415
Construction work in progress	N/A				193		298
Other property, plant and equipment (a)	20				31		15

Total property, plant and equipment					8,093		7,598
Less: accumulated depreciation					2,595		2,466

Property, plant and equipment, net				$	5,498	$	5,132

(a) Represents land held for future use and non utility property.

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.92	%	2.89	%	2.88	%
Gas	2.33	%	2.41	%	2.42	%
Common—electric and gas	7.68	%	8.40	%	7.24	%

See Note 1—Significant Accounting Polices for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 11—Debt and Credit Agreements for further information regarding Exelon's, ComEd's, and PECO's property, plant and equipment subject to mortgage liens.

Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

12 Months Ended

Dec. 31, 2012

Jointly Owned Utility Plant Net Ownership Amount [Line Items]

Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

7. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

Exelon, Generation, PECO and BGE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2012 and 2011 were as follows:

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(c) PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above.

(d) PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

Exelon's, Generation's, PECO's and BGE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon's, Generation's, PECO's and BGE's share of direct expenses of the jointly owned plants are included in fuel and operating and maintenance expenses on Exelon's and Generation's Consolidated Statements of Operations and in operating and maintenance expenses on PECO's and BGE's Consolidated Statements of Operations.

Exelon Generation Co L L C [Member]

Jointly Owned Utility Plant Net Ownership Amount [Line Items]

Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

7. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

Exelon, Generation, PECO and BGE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2012 and 2011 were as follows:

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

PECO Energy Co [Member]

Jointly Owned Utility Plant Net Ownership Amount [Line Items]

Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

7. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

Exelon, Generation, PECO and BGE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2012 and 2011 were as follows:

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

Intangible Assets (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Intangible Assets [Abstract]

Intangible Assets (Exelon, Generation, ComEd and PECO)

8. Intangible Assets (Exelon, Generation, ComEd and PECO)

Goodwill

Exelon's and ComEd's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2012 and 2011 were as follows:

	2012 and 2011
			Accumulated
	Gross		Impairment		Carrying
	Amount(a)		Losses		Amount

Balance, January 1,	$	4,608	$	1,983	$	2,625

Impairment losses		0		0		0

Balance, December 31,	$	4,608	$	1,983	$	2,625

__________

(a) Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events or circumstances indicate that goodwill is more likely than not impaired, such as a significant negative regulatory outcome, that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount.

In September 2011, the FASB issued authoritative guidance amending existing guidance on the annual assessment of goodwill for impairment. Under the revised guidance, which became effective January 1, 2012, entities assessing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test is required. Otherwise, no further testing is required.

If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a two-step, fair value based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.

Exelon assesses goodwill impairment at its ComEd reporting unit. Accordingly, any goodwill impairment charge at ComEd will affect Exelon's consolidated results of operations. Under the effective authoritative guidance for fair value measurement, Exelon and ComEd estimate the fair value of the ComEd reporting unit using a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd's business and includes an estimate of ComEd's terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity's residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd's business and the fair value of debt. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon's enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiple analysis.

2012 Interim Goodwill Impairment Assessment. In May 2012, the ICC issued a final Order (Order) in ComEd's 2011 formula rate proceeding under EIMA that reduced ComEd's annual revenue requirement being recovered in current rates by $168 million. Management concluded that the Order represented an event that required an interim goodwill impairment assessment and as a result, ComEd tested its goodwill for impairment as of May 31, 2012. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. Consistent with prior annual impairment tests, the estimated fair value of ComEd was determined using a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or management's best estimate of projected cash flows for ComEd's business. In performing the discounted cash flow analysis for the interim goodwill test, management assumed that ComEd would ultimately prevail in appealing certain aspects of the May Order, specifically the return on ComEd's pension asset and the use of year-end rate base in determining ComEd's annual revenue requirement being recovered in current rates. The disallowances related to the pension asset return and year-end rate base were estimated to reduce ComEd's revenue requirement recovered in rates by approximately $75 - $130 million annually. The assessment also reflected several favorable changes in certain market assumptions since the annual impairment assessment in 2011, including the weighted average cost of capital and market multiples.

Based on the results of the interim goodwill test, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test.

On October 3, 2012, the ICC issued its Rehearing Order in response to ComEd's expedited rehearing request. The Rehearing Order adopted ComEd's position on the return on its pension asset resulting in an increase in ComEd's annual revenue. See Note 3 - Regulatory Matters for further detail.

2012 Annual Goodwill Impairment Assessment. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and while certain factors indicated a reduction in fair value since May 31, 2012, ComEd determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitative assessment, ComEd evaluated, among other things, management's best estimate of projected operating and capital cash flows for ComEd's business (including the impacts of the Rehearing Order) as well as changes in certain other market conditions such as the discount rate and EBITDA multiples.

While neither the interim nor the annual assessments indicated an impairment of ComEd's goodwill, a change in management's assumption regarding the outcome of the IRS' challenge of Exelon's and ComEd's like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA, or changes in the significant assumptions described above could potentially result in a future impairment of ComEd's goodwill, which could be material. ComEd will assess whether its goodwill has been impaired in the first quarter of 2013 in connection with the reassessment of the like-kind exchange position and the associated charge to ComEd's earnings. See Note 12 for additional information.

Prior Goodwill Impairment Assessments. The 2011 and 2010 annual goodwill impairment assessments were performed as of November 1, 2011 and November 1, 2010, respectively. In each case, the first step of the annual impairment analysis, comparing the fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. ComEd will assess whether its goodwill has been impaired in the first quarter of 2013 in connection with the reassessment of the like-kind exchange position and the charge to ComEd's earnings. See Note 12 for additional information.

Other Intangible Assets

For discussion surrounding Exelon's and Generation's unamortized energy contracts, trade name and retail relationships recorded in conjunction with the Merger refer to Note 4 – Merger and Acquisitions.

Exelon's, Generation's and ComEd's other intangible assets, included in unamortized energy contract assets and deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2012:

								Estimated amortization expense
		Gross		Accumulated Amortization		Net		2013		2014		2015		2016		2017
Generation
	Exelon Wind acquisition (a)	$	224	$	(26)	$	198	$	14	$	14	$	14	$	14	$	14
	Antelope Valley acquisition (b)		190		0		190		7		8		8		8		8
ComEd
	Chicago settlement – 1999 agreement (c)		100		(72)		28		3		3		3		3		4
	Chicago settlement – 2003 agreement (d)		62		(34)		28		4		4		4		4		3

Total intangible assets		$	576	$	(132)	$	444	$	28	$	29	$	29	$	29	$	29

__________

(a) Refer to Note 4 – Merger and Acquisitions for additional information regarding Exelon Wind.

(b) Refer to Note 4 – Merger and Acquisitions for additional information regarding Antelope Valley.

(c) In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd's franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

(d) In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third party on the City of Chicago's behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation's obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.

The following table summarizes the amortization expense related to intangible assets for each of the years ended December 31, 2012, 2011 and 2010:

For the Year Ended December 31,	Exelon		Generation		ComEd

2012	$	20	$	13	$	7
2011		19		12		7
2010		8		1		7

Acquired Intangible Assets

Accounting guidance for business combinations requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. The valuation of the acquired intangible assets discussed below were estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the respective PPAs. Those measures are based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance.

Exelon Wind. The output of the acquired wind turbines has been sold under PPA contracts. The excess of the contract price of the PPAs over market prices was recognized as intangible assets at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible assets was approximately $224 million, which is recorded in unamortized energy contract assets within Exelon's and Generation's Consolidated Balance Sheets.

Key assumptions used in the valuation of the intangible assets include forecasted power prices and discount rate. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. The intangible assets are amortized on a straight-line basis over the period in which the associated contract revenues are recognized. The amortization expense is reflected as a decrease in operating revenue within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The weighted-average amortization period for these intangibles is approximately 18 years.

Antelope Valley. Upon completion of the development project, all of the output will be sold under a PPA with Pacific Gas & Electric Company. The excess of the contract price of the PPA over forecasted MPR-based market prices was recognized as an intangible asset at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible asset was approximately $190 million, which is recorded in unamortized energy contract assets within Exelon's and Generation's Consolidated Balance Sheets. While Generation expects to perform under the PPA once the construction of this project is complete, there is a risk of impairment if the project does not reach commercial operation.

Key assumptions used in the valuation of the intangible asset include forecasted MPR-based market prices and discount rate. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition date. The intangible asset will be amortized as a decrease in operating revenue within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income over the 25 year term of the underlying PPA.

Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, ComEd and PECO).

Exelon's, Generation's, ComEd's and PECO's other intangible assets, included in other current assets and other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As of December 31, 2012, and 2011, PECO had current AECs of $17 million and $14 million, respectively, and noncurrent AECs of $9 million and $16 million, respectively. As of December 31, 2012, and 2011, Generation had current RECs of $61 million and $0 million, respectively, and noncurrent RECs of $45 million and $6 million, respectively. As of December 31, 2012, and 2011, ComEd, had current RECs of $18 million and $9 million, respectively, and noncurrent RECs of $49 million and $97, respectively. See Notes 1 – Significant Accounting Policies, 3 - Regulatory Matters and Note 19 - Commitments and Contingencies for additional information on RECs and AECs.

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Fair Value of Financial Assets and Liabilities [Abstract]

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

9. 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, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures), and preferred securities as of December 31, 2012, and 2011:

Exelon

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	214	$	4	$	210	$	0	$	737	$	737
Long-term debt (including amounts
	due within one year)		18,745		0		20,244		276		12,627		14,488
Long-term debt to financing trusts			648		0		0		664		390		358
SNF obligation			1,020		0		763		0		1,019		886
Preferred securities of subsidiary			87		0		82		0		87		79

Generation

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	0	$	0	$	0	$	0	$	2	$	2
Long-term debt (including amounts
	due within one year)		7,483		0		7,591		258		3,677		4,231
SNF obligation			1,020		0		763		0		1,019		886

ComEd

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Long-term debt (including amounts
	due within one year)	$	5,567	$	0	$	6,530	$	18	$	5,665	$	6,540
Long-term debt to financing trust			206		0		0		212		206		184

PECO

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	210	$	0	$	210	$	0	$	225	$	225
Long-term debt (including amounts
	due within one year)		1,947		0		2,264		0		1,972		2,295
Long-term debt to financing trusts			184		0		0		188		184		174
Preferred securities			87		0		82		0		87		79

BGE

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Long-term debt (including amounts
	due within one year)	$	2,178	$	0	$	2,468	$	0	$	2,101	$	2,377
Long-term debt to financing trusts			258		0		0		263		258		256

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO's accounts receivable agreement (Level 2), and dividends payable (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. See Note 11 - Debt and Credit Agreements for additional information on PECO's accounts receivable agreement.

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.

Generation has fixed rate project financing debt (Level 3), the fair value of which 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, for certain government-backed debt, 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.

The Registrants also have tax-exempt debt (Level 3). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (i.e., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above.

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. Due to low trading volume of these securities (Level 3), qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, may be incorporated into the credit spreads that are used to obtain the fair value as described above. The securities are registered with the SEC and are public.

Preferred Securities. The fair value of these securities is determined based on the last closing price prior to quarter end, less accrued interest. The securities are registered with the SEC and are public.

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 equity securities, 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, non-exchange-based 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 non-exchange-based derivatives, investments priced using an alternative pricing mechanism, and middle market lending using third party valuations.

There were no transfers between Level 1 and Level 2 during the year ended December 31, 2012.

Exelon

The following tables present assets and liabilities measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	995	$	-	$	-	$	995
Nuclear decommissioning trust fund investments
Cash equivalents		245		-		-		245
Equity
Equity securities		1,480		-		-		1,480
Commingled funds		-		1,933		-		1,933
Equity funds subtotal		1,480		1,933		-		3,413
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,057		-		-		1,057
Debt securities issued by states of the United States
and political subdivisions of the states		-		321		-		321
Debt securities issued by foreign governments		-		93		-		93
Corporate debt securities		-		1,788		-		1,788
Federal agency mortgage-backed securities		-		24		-		24
Commercial mortgage-backed securities (non-agency)		-		45		-		45
Residential mortgage-backed securities (non-agency)		-		11		-		11
Mutual funds		-		23		-		23
Fixed income subtotal		1,057		2,305		-		3,362
Middle market lending		-		-		183		183
Other debt obligations		-		15		-		15
Nuclear decommissioning trust fund investments subtotal^(b)		2,782		4,253		183		7,218

Pledged assets for Zion decommissioning
Cash equivalents		-		23		-		23
Equity securities		14		-		-		14
Commingled funds		-		9		-		9
Equity funds subtotal		14		9		-		23
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		118		12		-		130
Debt securities issued by states of the United States						-
and political subdivisions of the states		-		37		-		37
Corporate debt securities		-		249		-		249
Federal agency mortgage-backed securities		-		49		-		49
Commercial mortgage-backed securities (non-agency)		-		6		-		6
Fixed income subtotal		118		353		-		471
Middle market lending		-		-		89		89
Other debt obligations		-		1		-		1
Pledged assets for Zion decommissioning subtotal^(c)		132		386		89		607

Rabbi trust investments
Cash equivalents		2		-		-		2
Mutual funds^(d)		69		-		-		69
Rabbi trust investments subtotal		71		-		-		71

Commodity mark-to-market derivative assets
Economic hedges		861		3,173		641		4,675
Proprietary trading		1,042		2,078		73		3,193
Effect of netting and allocation of collateral^(f)		(1,823)		(4,175)		(58)		(6,056)
Commodity mark-to-market assets subtotal^(g)		80		1,076		656		1,812

Interest rate mark-to-market derivative assets		-		114		-		114
Effect of netting and allocation of collateral		-		(51)		-		(51)
Interest rate mark-to-market derivative assets subtotal		-		63		-		63

Other Investments		2		-		17		19

Total assets		4,062		5,778		945		10,785

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041)		(2,289)		(236)		(3,566)
Proprietary trading		(1,084)		(1,959)		(78)		(3,121)
Effect of netting and allocation of collateral^(f)		2,042		4,020		25		6,087
Commodity mark-to-market liabilities subtotal^(g)(h)		(83)		(228)		(289)		(600)

Interest rate mark-to-market derivative liabilities		-		(84)		-		(84)
Effect of netting and allocation of collateral		-		51		-		51
Interest rate mark-to-market derivative liabilities subtotal		-		(33)		-		(33)

Deferred compensation		-		(102)		-		(102)

Total liabilities		(83)		(363)		(289)		(735)

Total net assets	$	3,979	$	5,415	$	656	$	10,050

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	861	$	0	$	0	$	861
Nuclear decommissioning trust fund investments
Cash equivalents		562		0		0		562
Equity
Equity securities		1,275		0		0		1,275
Commingled funds		0		1,822		0		1,822
Equity funds subtotal		1,275		1,822		0		3,097
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,014		33		0		1,047
Debt securities issued by states of the United States
and political subdivisions of the states		0		541		0		541
Debt securities issued by foreign governments		0		16		0		16
Corporate debt securities		0		778		0		778
Federal agency mortgage-backed securities		0		357		0		357
Commercial mortgage-backed securities (non-agency)		0		83		0		83
Residential mortgage-backed securities (non-agency)		0		5		0		5
Mutual funds		0		47		0		47
Fixed income subtotal		1,014		1,860		0		2,874
Middle market lending		0		0		13		13
Other debt obligations		0		18		0		18
Nuclear decommissioning trust fund investments subtotal^(b)		2,851		3,700		13		6,564

Pledged assets for Zion decommissioning
Equity
Equity securities		35		0		0		35
Commingled funds		0		30		0		30
Equity funds subtotal		35		30		0		65
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		54		26		0		80
Debt securities issued by states of the United States
and political subdivisions of the states		0		65		0		65
Corporate debt securities		0		314		0		314
Federal agency mortgage-backed securities		0		121		0		121
Commercial mortgage-backed securities (non-agency)		0		10		0		10
Commingled funds		0		20		0		20
Fixed income subtotal		54		556		0		610
Middle market lending		0		0		37		37
Other debt obligations		0		13		0		13
Pledged assets for Zion decommissioning subtotal^(c)		89		599		37		725

Rabbi trust investments
Cash equivalents		2		0		0		2
Mutual funds^(d)(e)		34		0		0		34
Rabbi trust investments subtotal		36		0		0		36

Commodity mark-to-market derivative assets
Cash flow hedges		0		857		0		857
Economic hedges		0		1,653		124		1,777
Proprietary trading		0		240		48		288
Effect of netting and allocation of collateral^(f)		0		(1,827)		(28)		(1,855)
Commodity mark-to-market assets^(g)		0		923		144		1,067
Interest rate mark-to-market derivative assets		0		15		0		15

Total assets		3,837		5,237		194		9,268

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		0		(13)		0		(13)
Economic hedges		(1)		(1,137)		(119)		(1,257)
Proprietary trading		0		(236)		(28)		(264)
Effect of netting and allocation of collateral^(f)		0		1,295		20		1,315
Commodity mark-to-market liabilities^(h)		(1)		(91)		(127)		(219)
Interest rate mark-to-market liabilities		0		(19)		0		(19)
Deferred compensation		0		(73)		0		(73)

Total liabilities		(1)		(183)		(127)		(311)

Total net assets	$	3,836	$	5,054	$	67	$	8,957

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b) Excludes net assets (liabilities) of $30 million and $(57) million at December 31, 2012 and December 31, 2011, 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 $7 million and $9 million at December 31, 2012 and December 31, 2011, 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 include $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan. These funds are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(e) Excludes $28 million and $25 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

(f) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $532 million and $8 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2011.

(g) The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million and $0 million at December 31, 2012 and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of Generation's financial swap contract with ComEd.

(h) The Level 3 balance includes the current and noncurrent liability of $18 million and $49 million at December 31, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2012 and 2011:

For the Year Ended December 31, 2012		Nuclear Decommissioning Trust Fund Investment		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives(b)		Other Investments		Total
Balance as of January 1, 2012		$	13	$	37	$	17		$	0	$	67
Total realized / unrealized gains (losses)
	Included in net income		-		-		(119)	(a)		-		(119)
	Included in other comprehensive income		-		-		-			-		-
	Included in regulatory assets		1		-		39			-		40
	Included in payable for Zion Station decommissioning		-		-		-			-		-
Change in collateral			-		-		(32)			-		(32)
Purchases, sales, issuances and settlements
	Purchases		169		63		334	(c)		17		583
	Sales		-		(11)		-			0		(11)
Transfers into Level 3			-		-		39			0		39
Transfers out of Level 3			-		-		89			-		89

Balance as of December 31, 2012		$	183	$	89	$	367		$	17	$	656
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2012	$	-	$	-	$	37		$	0	$	37

(a) Includes the reclassification of $156 million of realized losses due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(b) Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI.

(c) Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2012 and 2011:


		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2012	$	(153)	$	34
Change in the unrealized gains relating to assets and liabilities
	held for the year ended December 31, 2012	$	13	$	24

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2011	$	108	$	(8)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the year ended December 31, 2011	$	137	$	(5)

Generation

The following tables present assets and liabilities measured and recorded at fair value on Generation's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:

As of December 31, 2012	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	487	$	0	$	0	$	487
Nuclear decommissioning trust fund investments
Cash equivalents		245		0		0		245
Equity
Equity securities		1,480		0		0		1,480
Commingled funds		0		1,933		0		1,933
Equity funds subtotal		1,480		1,933		0		3,413
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,057		0		0		1,057
Debt securities issued by states of the United States and
political subdivisions of the states		0		321		0		321
Debt securities issued by foreign governments		0		93		0		93
Corporate debt securities		0		1,788		0		1,788
Federal agency mortgage-backed securities		0		24		0		24
Commercial mortgage-backed securities (non-agency)		0		45		0		45
Residential mortgage-backed securities (non-agency)		0		11		0		11
Mutual funds		0		23		0		23
Fixed income subtotal		1,057		2,305		0		3,362
Middle market lending		0		0		183		183
Other debt obligations		0		15		0		15
Nuclear decommissioning trust fund investments subtotal(b)		2,782		4,253		183		7,218

Pledged assets for Zion Station decommissioning
Cash equivalents		0		23		0		23
Equity
Equity securities		14		0		0		14
Commingled funds		0		9		0		9
Equity funds subtotal		14		9		0		23
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		118		12		0		130
Debt securities issued by states of the United States and
political subdivisions of the states		0		37		0		37
Corporate debt securities		0		249		0		249
Federal agency mortgage-backed securities		0		49		0		49
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Fixed income subtotal		118		353		0		471
Middle market lending		0		0		89		89
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		132		386		89		607

Rabbi trust investments
Cash equivalents		1		0		0		1
Mutual funds^(d)(e)		13		0		0		13
Rabbi trust investments subtotal		14		0		0		14

Commodity mark-to-market derivative assets
Economic hedges		861		3,173		867		4,901
Proprietary trading		1,042		2,078		73		3,193
Effect of netting and allocation of collateral^(f)		(1,823)		(4,175)		(58)		(6,056)
Commodity mark-to-market assets subtotal^(g)		80		1,076		882		2,038

Interest Rate mark-to-market derivative assets		0		101		0		101
Effect of netting and allocation of collateral		0		(51)		0		(51)
Interest Rate mark-to-market derivative assets subtotal		0		50		0		50

Other investments		2		0		17		19

Total assets		3,497		5,765		1,171		10,433

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041)		(2,289)		(169)		(3,499)
Proprietary trading		(1,084)		(1,959)		(78)		(3,121)
Effect of netting and allocation of collateral^(f)		2,042		4,020		25		6,087
Commodity mark-to-market liabilities subtotal		(83)		(228)		(222)		(533)

Interest rate mark-to-market derivative liabilities		0		(84)		0		(84)
Effect of netting and allocation of collateral		0		51		0		51
Interest rate mark-to-market derivative liabilities subtotal		0		(33)		0		(33)

Deferred compensation		0		(28)		0		(28)

Total liabilities		(83)		(289)		(222)		(594)

Total net assets	$	3,414	$	5,476	$	949	$	9,839

As of December 31, 2011	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	466	$	0	$	0	$	466
Nuclear decommissioning trust fund investments
Cash equivalents		562		0		0		562
Equity
Equity securities		1,275		0		0		1,275
Commingled funds		0		1,822		0		1,822
Equity funds subtotal		1,275		1,822		0		3,097
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,014		33		0		1,047
Debt securities issued by states of the United States and
political subdivisions of the states		0		541		0		541
Debt securities issued by foreign governments		0		16		0		16
Corporate debt securities		0		778		0		778
Federal agency mortgage-backed securities		0		357		0		357
Commercial mortgage-backed securities (non-agency)		0		83		0		83
Residential mortgage-backed securities (non-agency)		0		5		0		5
Mutual funds		0		47		0		47
Fixed income subtotal		1,014		1,860		0		2,874
Middle market lending		0		0		13		13
Other debt obligations		0		18		0		18
Nuclear decommissioning trust fund investments subtotal(b)		2,851		3,700		13		6,564

Pledged assets for Zion Station decommissioning
Equity
Equity securities		35		0		0		35
Commingled funds		0		30		0		30
Equity funds subtotal		35		30		0		65
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		54		26		0		80
Debt securities issued by states of the United States and
political subdivisions of the states		0		65		0		65
Corporate debt securities		0		314		0		314
Federal agency mortgage-backed securities		0		121		0		121
Commercial mortgage-backed securities (non-agency)		0		10		0		10
Commingled funds		0		20		0		20
Fixed income subtotal		54		556		0		610
Middle market lending		0		0		37		37
Other debt obligations		0		13		0		13
Pledged assets for Zion Station decommissioning subtotal^(c)		89		599		37		725

Rabbi trust investments^(d)(e)		4		0		0		4

Commodity mark-to-market derivative assets
Cash flow hedges		0		857		694		1,551
Other derivatives		0		1,653		124		1,777
Proprietary trading		0		240		48		288
Effect of netting and allocation of collateral^(f)		0		(1,827)		(28)		(1,855)
Commodity mark-to-market assets subtotal^(g)		0		923		838		1,761


Total assets		3,410		5,222		888		9,520

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		0		(13)		0		(13)
Other derivatives		(1)		(1,137)		(13)		(1,151)
Proprietary trading		0		(236)		(28)		(264)
Effect of netting and allocation of collateral^(f)		0		1,295		20		1,315
Commodity mark-to-market liabilities subtotal		(1)		(91)		(21)		(113)

Interest rate mark-to-market derivative liabilities		0		(19)		0		(19)
Deferred compensation		0		(18)		0		(18)

Total liabilities		(1)		(128)		(21)		(150)

Total net assets	$	3,409	$	5,094	$	867	$	9,370

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(c) Excludes net assets of $7 million and $9 million at December 31, 2012 December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d) The $13 million mutual funds held by the Rabbi trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(e) Excludes $8 million and $7 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

(g) The Level 3 balance includes current and noncurrent assets for Generation of $226 million and $0 million at December 31, 2012 and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2012, and 2011:.

For the Year Ended December 31, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives				Other Investments	Total
Balance as of January 1, 2012		$	13	$	37	$	817			-	$	867
Total unrealized / realized gains (losses)
	Included in income		-		-		(112)	(a)		-		(112)
	Included in other comprehensive income		-		-		(475)	(b)		-		(475)
	Included in noncurrent payables to affiliates		1		-		-			-		1
Change in collateral			-		-		(32)			-		(32)
Purchases, sales, issuances and settlements
	Purchases		169		63		334	(c)		17		583
	Sales		-		(11)		-			-		(11)
Transfers into Level 3			-		-		39					39
Transfers out of Level 3			-		-		89			-		89

Balance as of December 31, 2012		$	183	$	89	$	660		$	17	$	949
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2012	$	-	$	-	$	(12)		$	-	$	(12)

(a) Includes the reclassification of $100 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(b) Includes $98 million of increases in fair value and realized losses due to settlements of $566 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2012. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

(c) Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2012	$	(146)	$	34
Change in the unrealized gains (losses) relating to assets and
	liabilities held for the year ended December 31, 2012	$	(25)	$	13

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2011	$	108	$	(8)
Change in the unrealized gains (losses) relating to assets and
	liabilities held for the year ended December 31, 2011	$	137	$	(5)

ComEd

The following tables present assets and liabilities measured and recorded at fair value on ComEd's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:

As of December 31, 2012		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	111	$	0	$	0	$	111
Rabbi trust investments
Mutual funds			8		0		0		8
	Rabbi trust investment subtotal		8		0		0		8

Total assets			119		0		0		119

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities (b)(c)			0		0		(293)		(293)

Total liabilities			0		(8)		(293)		(301)

Total net assets (liabilities)		$	119	$	(8)	$	(293)	$	(182)

As of December 31, 2011		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents (a)		$	173	$	0	$	0	$	173
Rabbi trust investments
Cash equivalents			2		0		0		2
Mutual funds			19		0		0		19
	Rabbi trust investment subtotal		21		0		0		21

Total assets			194		0		0		194

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities (b)(c)			0		0		(800)		(800)

Total liabilities			0		(8)		(800)		(808)

Total net assets (liabilities)		$	194	$	(8)	$	(800)	$	(614)

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b) The Level 3 balance includes the current and noncurrent liability of $226 million and $0 million at December 31, 2012, respectively, and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of ComEd's financial swap contract with Generation which eliminates upon consolidation in Exelon's Consolidated Financial Statements.

(c) The Level 3 balance includes the current and noncurrent liability of $18 million and $49 million at December 31, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended and December 31, 2012, and 2011:

For the Year Ended December 31, 2012	Mark-to-Market Derivatives
Balance as of January 1, 2012	$	(800)
Total realized / unrealized gains included in regulatory assets (a)(b)		507
Balance as of December 31, 2012	$	(293)

(a) Includes $98 million of decreases in fair value and realized gains due to settlements of $566 million associated with ComEd's financial swap contract with Generation for the year ended December 31, 2012. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

(b) Includes $34 million of increases in the fair value and realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2012 .

Includes $170 million of increases in fair value and $451 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the year ended December 31, 2011. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $110 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2011.

PECO

The following tables present assets and liabilities measured and recorded at fair value on PECO's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	346	$	0	$	0	$	346
Rabbi trust investments - mutual funds^(b)(c)		9		0		0		9

Total assets		355		0		0		355

Liabilities
Deferred compensation obligation		0		(18)		0		(18)

Total liabilities		0		(18)		0		(18)

Total net assets (liabilities)	$	355	$	(18)	$	0	$	337

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	175	$	0	$	0	$	175
Rabbi trust investments - mutual funds^(b)(c)		9		0		0		9

Total assets		184		0		0		184

Liabilities
Deferred compensation obligation		0		(21)		0		(21)

Total liabilities		0		(21)		0		(21)

Total net assets (liabilities)	$	184	$	(21)	$	0	$	163

BGE

The following tables present assets and liabilities measured and recorded at fair value on BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	33	$	0	$	0	$	33
Rabbi trust investments - mutual funds		5		0		0		5

Total assets		38		0		0		38

Liabilities
Deferred compensation obligation		0		(5)		0		(5)

Total liabilities		0		(5)		0		(5)

Total net assets (liabilities)	$	38	$	(5)	$	0	$	33

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	33	$	0	$	0	$	33

Total assets		33		0		0		33

Liabilities


Total net assets (liabilities)	$	33	$	0	$	0	$	33

BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2012.

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 nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation'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.

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.

Equity 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 and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month; however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. Commingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities.

Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

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. The investments are in fixed-income commingled funds and mutual funds, including short-term investment 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. The values of some of these funds are publicly quoted. For fixed-income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Fixed-income commingled funds and mutual funds which are publicly quoted, such as money market funds, have been categorized as Level 1 given the clear observability of the prices.

Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO). 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 non-exchange-based 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 non-exchange-based derivative contracts is 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 non-exchange-based 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' non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, 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 10 — 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 in 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. 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 generally do not occur. 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.

Disclosed below is detail surrounding the Registrants' significant Level 3 valuations. The most significant position is the long term intercompany swap with ComEd, which is further discussed in Note 10 – Derivative Financial Instruments. The calculated fair value includes marketability discounts for margining provisions and notional size. Generation's remaining Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation's own credit quality for liabilities. The level of observability of a forward commodity price is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly 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 instruments 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 generally less than $4 and $.25 for power and natural gas respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Item 3. – Quantitative and Qualitative Disclosures About Market Risk for information regarding the maturity by year of the 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 10 – Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.

Type of trade	Fair Value at December 31, 2012 (d)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	473	Discounted Cash Flow	Forward power price	$	14		-	$	79
			Discounted Cash Flow	Forward gas price	$	3.26		-	$	6.27
			Option Model	Volatility percentage		28	%	-		132	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	(6)	Discounted Cash Flow	Forward power price	$	15		-	$	106
			Option Model	Volatility percentage		16	%	-		48	%

Mark-to-market derivatives – Transactions with affiliates (Generation and ComEd) (b)	$	226	Discounted Cash Flow	Marketability reserve		8	%	-		9	%

Mark-to-market derivatives (ComEd)	$	(67)	Discounted Cash Flow	Forward heat rate (c)		8	%	-		9.5	%
				Marketability reserve		3.5	%	-		8.3	%
				Renewable factor		81	%	-		123	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation.
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.
The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012.

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 volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us 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 the fair value of these loans is determined using a combination of valuations 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 applications of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability and relative performance.

Because Generation relies on third party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its' middle market lending, 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' middle market lending, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

For the Year Ended December 31, 2011		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Total
Balance as of January 1, 2011			$	0	$	0	$	50		$	50
Total realized / unrealized gains (losses)
	Included in income			1		0		99			100
	Included in other comprehensive income			0		0		(25)	(a)		(25)
	Included in regulatory liabilities			2		0		(106)	(b)		(104)
Change in collateral				0		0		6			6
Purchases, sales, issuances and settlements
	Purchases			10		60		10			80
	Sales			0		(23)		0			(23)
Transfers out of Level 3				0		0		(17)			(17)
Balance as of December 31, 2011			$	13	$	37	$	17		$	67
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2011		$	1	$	0	$	131		$	132

(a) Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

(b) Excludes $170 million of increases in fair value and $451 million of realized losses due to settlements associated with Generation's financial swap contract with ComEd and $5 million of changes in the fair value of Generation's block contracts with PECO for the year ended December 31, 2011. All items eliminate upon consolidation if Exelon's Consolidated Financial Statements.

For the Year Ended December 31, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of January 1, 2011		$	0	$	0	$	1,030		$	1,030
Total realized / unrealized gains (losses)
	Included in income		1		0		99	(a)		100
	Included in other comprehensive income		0		0		(311)	(b)		(311)
	Included in payable for Zion Station decommissioning		2		0		0			2
Changes in collateral			0		0		6			6
Purchases, sales, issuances and settlements
	Purchases		10		60		10			80
	Sales		0		(23)		0			(23)
Transfers out of Level 3 - Liability			0		0		(17)			(17)

Balance as of December 31, 2011		$	13	$	37	$	817		$	867

The amount of total gains included in income attributed to
	the change in unrealized gains related to assets and liabilities as of December 31, 2011	$	1	$	0	$	131		$	132

(a) Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

(b) Includes $170 million of increases in fair value and $451 million of realized losses reclassified from OCI due to settlements associated with Generation's financial swap contract with ComEd for the year ended December 31, 2011, and $5 million of decreases in fair value due to settlement of Generation's block contracts with PECO for the year ended December 31, 2011. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

Twelve Months Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(971)
Total realized / unrealized gains included in regulatory assets (a)(b)		171
Balance as of December 31, 2011	$	(800)

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b) The mutual funds held by the Rabbi trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(c) Excludes $13 million of the cash surrender value of life insurance investments at December 31, 2012 and 2011, respectively.

PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2012.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2011:

Year Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(9)
Total realized gains included in regulatory assets		9	(a)
Balance as of December 31, 2011	$	0

(a) Includes an increase of $5 million related to the settlement of PECO's block contracts with Generation, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. Generation's block contracts with PECO expired on December 31, 2011.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13537-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13504-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Derivative Financial Instruments [Abstract]

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

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

The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk.

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 contracts as well as 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 will no longer utilize 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 will be 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 19 – Commitments and Contingencies. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall energy marketing activities.

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

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2012, the percentage of expected generation hedged for the major reportable segments was 94%-97%, 62%-65% and 27%-30% for 2013, 2014, and 2015, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including, sales to ComEd, PECO and BGE to serve their retail load.

ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement process, which are further discussed in Note 3 – Regulatory Matters, qualify for the NPNS exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd's price risk related to power procurement is limited.

In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which, along with ComEd's remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volume is 3,000 MWs through May 2013. The terms of the financial swap contract require Generation to pay the around-the-clock market price for a portion of ComEd's electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that was originally designated by Generation as a cash flow hedge. As discussed previously, effective with the date of merger with Constellation, Generation de-designated this swap as a cash flow hedge and began recording changes in fair value through current earnings as of that date. Generation records the fair value of the swap on its balance sheet and originally recorded changes in fair value to OCI. The value frozen in OCI as of the date of merger for this swap is reclassified into Generation's earnings as the swap settles. ComEd has not elected hedge accounting for this derivative financial instrument. Since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and, therefore, the change in fair value each period is recorded as a regulatory asset or liability on ComEd's Consolidated Balance Sheets. See Note 3 – Regulatory Matters for additional information regarding the Illinois Settlement Legislation. In Exelon's consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 3 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO's price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO's full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded on PECO's Consolidated Balance Sheet were amortized over the terms of the contracts, which ended on December 31, 2011.

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 normal purchases and normal sales 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 2012 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 2012 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 Standard Offer Service requirements through full requirements contracts. BGE's full requirements contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance.

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 market-based rates incentive 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 normal purchases and normal sales 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 12,958 GWh, 5,742 GWh and 3,625 Gwh for the years ended December 31, 2012, 2011 and 2010, 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 Risk (Exelon, Generation, ComEd, PECO and BGE)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2012, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and $452 million of notional amounts of pre-issuance hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper and PECO Accounts Receivables Facility) and fixed-to-floating swaps would result in less than $2 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2012. Below is a summary of the interest rate hedges as of December 31, 2012.

		Generation										Other		Exelon
Description		Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading (a)		Collateral and Netting (b)		Subtotal		Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	-	$	3	$	20	$	(19)	$	4	$	-	$	4
Mark-to-market derivative assets (Noncurrent Assets)		38	$	8	$	32		(32)		46		13		59
Total mark-to-market derivative assets	$	38	$	11	$	52	$	(51)	$	50	$	13	$	63

Mark-to-market derivative liabilities (Current Liabilities)	$	(1)	$	(1)	$	(19)	$	19	$	(2)	$	0	$	(2)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(31)	$	0	$	(32)		32		(31)		0		(31)
Total mark-to-market derivative liabilities	$	(32)	$	(1)	$	(51)	$	51	$	(33)	$	0	$	(33)

Total mark-to-market derivative net assets (liabilities)	$	6	$	10	$	1	$	0	$	17	$	13	$	30

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 interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and 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:

		Gain (Loss) on Swaps						Gain (Loss) on Borrowings
		Twelve Months Ended						Twelve Months Ended
		December 31,						December 31,
Income Statement Classification		2012		2011		2010		2012		2011		2010
Interest expense (a)	$	(6)	$	1	$	4	$	(6)	$	(1)	$	(4)

______ ____

For the year ended December 31, 2012, the loss on the swaps in the table above includes $12 million reclassified to earnings, with an immaterial amount excluded from hedge effectiveness testing.

At December 31, 2012, and December 31, 2011, Exelon had $650 million and $100 million, respectively, of notional amounts of fixed-to-floating fair value hedges outstanding related to interest rate swaps, with unrealized gain of $49 million and $15 million, respectively, which expire in 2015. Upon merger closing, $550 million of fixed-to-floating interest rate swaps previously at Constellation with a fair value of $44 million, as of March 12, 2012, were re-designated as fair value hedges. During the years ended December 31, 2012, and December 31, 2011, 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 acquisition, as discussed in Note 11 – Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of April 5, 2014, by which date Generation anticipates the DOE loan to be fully drawn. The swap hedges approximately 75% of Generation's future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge will be recorded in other comprehensive income within Generation's Consolidated Balance Sheets, with any ineffectiveness recorded in Generation's Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, will be amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan.

As Generation draws down on the loan, a portion of the cash flow hedge will be de-designated and the related gains or losses going forward will be reflected in earnings. In order to mitigate this earnings impact, a series of offsetting hedge transactions are executed as Generation draws on the loan.

Antelope Valley received its first loan advance on April 5, 2012, and several additional advances subsequently, as described in Note 11 - Debt and Credit Agreements. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $165 million, 75% of the loan advance amount to offset portions of the original interest rate hedge, which are de-designated as cash flow hedges. The remaining cash flow hedge has a notional amount of $320 million. At December 31, 2012, Generation's mark-to-market non-current derivative liability relating to the interest rate swap in connection with the loan agreement to fund Antelope Valley was $28 million.

During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed forward starting 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 $29 million as of December 31, 2012 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At December 31, 2012, the subsidiary had a $4 million non-current derivative liability related to these swaps.

During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed forward starting interest rate swap to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $29 million as of December 31, 2012 and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2012, the subsidiary had an immaterial non-current derivative liability related to the swap.

During the third quarter of 2012, Exelon entered into $75 million floating-to-fixed forward starting interest rate hedges to manage interest rate risks associated with anticipated future debt issuance. These swaps are designated as cash flow hedges. At December 31, 2012, there is $1 million non-current derivative asset related to these swaps.

During the years ended December 31, 2012, and 2011, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

Economic Hedges. At December 31, 2012, Exelon had $150 million of notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with an unrealized gain of $5 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the period from March 12 to December 31, 2012, the impact on the results of operations was immaterial.

Fair Value Measurement (Exelon, Generation, ComEd, PECO and BGE)

Fair value accounting guidance 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 master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation's energy related cash flow hedges, economic hedges, and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. 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.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2012:

		Generation								ComEd				Exelon
		Generation								ComEd				Exelon
						Collateral
		Economic		Proprietary		and				Economic		Intercompany		Total
Derivatives		Hedges (a)		Trading		Netting(b)		Subtotal (c)		Hedges (a)(d)		Eliminations (a)		Derivatives

Mark-to-market
	derivative assets (current assets)	$	2,883	$	2,469	$	(4,418)	$	934	$	0	$	0	$	934
Mark-to-market
	derivative assets with affiliate (current assets)		226		0		0		226		0		(226)		0
Mark-to-market
	derivative assets (noncurrent assets)		1,792		724		(1,638)		878		0		0		878

Total mark-to-market
	derivative assets	$	4,901	$	3,193	$	(6,056)	$	2,038	$	0	$	(226)	$	1,812

Mark-to-market
	derivative liabilities (current liabilities)	$	(2,419)	$	(2,432)	$	4,519	$	(332)	$	(18)	$	0	$	(350)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		(226)		226		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(1,080)		(689)		1,568		(201)		(49)		0		(250)

Total mark-to-market
	derivative liabilities	$	(3,499)	$	(3,121)	$	6,087	$	(533)	$	(293)	$	226	$	(600)

Total mark-to-market
	derivative net assets (liabilities)	$	1,402	$	72	$	31	$	1,505	$	(293)	$	0	$	1,212

__________

(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $28 million non current liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above.

(b) Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c) Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(214) million and $(131) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $31 million at December 31, 2012.

(d) 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, 2011:

Cash Flow Hedges (Exelon, Generation and ComEd). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load 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 will be 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. The net unrealized gains associated with the de-designated cash flow hedges prior to the merger was $1,928 million including $693 million related to the intercompany swap with ComEd. Approximately $684 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, including approximately $219 million related to the financial swap with ComEd. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2013 through 2014.

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item or when it is no longer probable that the forecasted transaction will occur. For the years ended December 31, 2012 and 2011, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The table below provides the activity of accumulated OCI related to cash flow hedges for the years ended December 31, 2012 and 2011, 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

Income Statement Location

Energy Related Hedges

Total Cash Flow Hedges

Accumulated OCI derivative gain at

January 1, 2011

1,011

(a)(d)

400

Effective portion of changes in fair value

504

(b)

402

(e)

Reclassifications from accumulated OCI to

net income

Operating Revenues

(585)

(c)

(309)

Ineffective portion recognized in income

Purchased Power

(5)

Accumulated OCI derivative gain at

December 31, 2011

925

(a)(d)

488

Effective portion of changes in fair value

432

(b)

330

(e)

Reclassifications from accumulated OCI to

net income

Operating Revenues

(828)

(c)

(453)

Ineffective portion recognized in income

Operating Revenues

Accumulated OCI derivative gain at

December 31, 2012

532

(a)(d)

368

__________

(a) Includes $133 million, $420 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012, 2011 and 2010, respectively, and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO for the year ended December 31, 2010.

(b) Includes $88 million and $104 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $2 million of gains, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended December 31, 2010. As of the merger date, cash flow hedges were discontinued, as such, this amount represents changes in fair value prior to the merger date.

(c) Includes $375 million and $273 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $3 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the block contracts with PECO for the year ended December 31, 2011.

(d) Excludes $20 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2012 and 2011, respectively.

(e) Includes $9 million and $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2012 and 2011, respectively

During the years ended December 31, 2012, 2011, and 2010 Generation's cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,368 million, $968 million and $1,125 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. This price difference was actively managed through other instruments, which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices were losses of $5 million and gains of $10 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Exelon's energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $747 million pre-tax gain for the year ended December 31, 2012, and a $512 million and $754 million pre-tax gain for the years ended 2011 and 2010, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million and gains of $10 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Neither Exelon nor Generation will not incur changes in cash flow hedge ineffectiveness in future periods as all commodity cash flow hedge positions were de-designated prior to the merger date.

Economic Hedges (Exelon and Generation). These instruments represent hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and physical forward sales and purchases. For the years ended December 31, 2012, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense 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 3rd quarter of 2012, Generation completed a non-cash exchange by issuing a new in-the-money derivative with a new counterparty in exchange for novating to them existing in-the-money trades with the old counterparty for a total of $51 million. This transaction did not have any Income Statement effect to Generation. 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 Eliminations	Exelon
				Purchased
	Operating			Power				Operating
Year Ended December 31, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(362)	$	215	$	(147)	$	(94)	$	(241)
Reclassification to realized at settlement		429		238		667		101		768
Net mark-to-market gains (losses)	$	67	$	453	$	520	$	7	$	527

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	87	$	131	$	218
Reclassification to realized at settlement		(296)		(219)		(515)
Net mark-to-market (losses) (b)	$	(209)	$	(88)	$	(297)

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	258	$	(40)	$	218
Reclassification to realized at settlement		(516)		1		(515)
Net mark-to-market (losses) (b)	$	(258)	$	(39)	$	(297)

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2010 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	389	$	389
Reclassification to realized at settlement		0		(304)		(304)
Net mark-to-market (losses) (b)	$	0	$	85	$	85

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 are recorded to operating revenues and eliminated in consolidation.
Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues.

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2012, and 2011, 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 derivative instruments entered into for proprietary trading purposes. 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.

		For the Years Ended
	Location on Income	December 31,
	Statement	2012		2011		2010
Change in fair value	Operating Revenue	$	(12)	$	23	$	26
Reclassification to realized at
settlement	Operating Revenue		108		(26)		(24)

Net mark-to-market gains	Operating Revenue	$	96	$	(3)	$	2

Credit Risk (Exelon, Generation, ComEd, PECO and BGE)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation's credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty's margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation's credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation's credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2012. 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 do not include credit risk exposure from uranium procurement contracts or exposure through exchanges (i.e. NYMEX, ICE), further discussed in Item 7A - Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $54 million, $56 million and $31 million, respectively.

	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of December 31, 2012	Collateral		Collateral (a)		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,984	$	347	$	1,637		1	$	262
Non-investment grade		28		24		4		0		0
No external ratings
Internally rated - investment grade		512		10		502		1		271
Internally rated - non-investment grade		41		3		38		0		0
Total	$	2,565	$	384	$	2,181		2	$	533

Net Credit Exposure by Type of Counterparty	December 31, 2012

Investor-owned utilities, marketers and power producers		$	865
Energy cooperatives and municipalities			786
Financial Institutions			422
Other			108
Total		$	2,181

(a) As of December 31, 2012, credit collateral held from counterparties where Generation had credit exposure included $344 million of cash and $40 million of letters of credit .

ComEd's power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd's net credit exposure. As of December 31, 2012, ComEd's credit exposure to suppliers was immaterial.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further 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. As of December 31, 2012, PECO had no net credit exposure with suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further 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; however, the natural gas asset managers have provided $20 million in parental guarantees related to these agreements. As of December 31, 2012, PECO had credit exposure of $7 million under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further 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 seller's credit exposure is calculated each business day. As of December 31, 2012, BGE had no net credit exposure with suppliers.

BGE's regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE's recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers' demands, which are not covered by the gas cost adjustment clause. At December 31, 2012, BGE had credit exposure of $8 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third party suppliers.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)

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

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

Credit-Risk Related Contingent Feature		December 31, 2012
Gross Fair Value of Derivative Contracts Containing this Feature (a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b)	Net Fair Value of Derivative Contracts Containing This Feature (c)


($1,849)	$1,426	($423)


Credit-Risk Related Contingent Feature		December 31, 2011
Gross Fair Value of Derivative Contracts Containing this Feature (a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b)	Net Fair Value of Derivative Contracts Containing This Feature (c)


($1,014)	$928	($86)

Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.
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.
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 has cash collateral posted of $527 million and letters of credit posted of $563 million and cash collateral held of $499 million and letters of credit held of $45 million as of December 31, 2012 and cash collateral held of $542 million and letters of credit held of $89 million at December 31, 2011. In the event of a credit downgrade below investment grade (i.e. BB+ or Ba1), Exelon Generation Company, LLC and Constellation Energy Commodities Group, Inc. could be required to post additional collateral of $1,920 million as of December 31, 2012, and $1,612 million as of December 31, 2011. 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 their debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2012, Generation's and Exelon's swaps were in an asset position, with a fair value of $17 million and $30 million, respectively.

See Note 21 – Segment Information for further information regarding the letters of credit supporting the cash collateral.

Generation entered into SFCs 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 the financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody's or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd's standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2012, ComEd held neither cash nor letters of credit 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 December 31, 2012, 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 1 – Significant Accounting Policies for further information.

PECO's natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2012, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2012, PECO could have been required to post approximately $35 million of collateral to its counterparties.

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

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

BGE's natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2012, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2012, BGE could have been required to post approximately $124 million of collateral to its counterparties.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

As of December 31, 2012, and December 31, 2011, $3 million and $2 million, respectively, of cash collateral received was not offset against derivative positions because they were not associated with energy-related derivatives.

		Generation										ComEd		Other				Exelon
		Generation										ComEd		Other				Exelon
								Collateral
		Cash Flow		Economic		Proprietary		and				Economic		Economic		Intercompany		Total
	Derivatives	Hedges (a)		Hedges		Trading		Netting(b)		Subtotal (c)		Hedges (a) (d)		Hedges		Eliminations (a)		Derivatives
Mark-to-market
	derivative assets (current assets)	$	438	$	1,195	$	217	$	(1,418)	$	432	$	0	$	0	$	0	$	432
Mark-to-market
	derivative assets with affiliate (current assets)		503		0		0		0		503		0		0		(503)		0
Mark-to-market
	derivative assets (noncurrent assets)		419		582		71		(437)		635		0		15		0		650
Mark-to-market
	derivative assets with affiliate (noncurrent assets)		191		0		0		0		191		0		0		(191)		0

Total mark-to-market
	derivative assets	$	1,551	$	1,777	$	288	$	(1,855)	$	1,761	$	0	$	15	$	(694)	$	1,082

Mark-to-market
	derivative liabilities (current liabilities)	$	(9)	$	(965)	$	(194)	$	1,065	$	(103)	$	(9)	$	0	$	0	$	(112)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		0		(503)		0		503		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(4)		(186)		(70)		250		(10)		(97)		0		0		(107)
Mark-to-market
	derivative liability with affiliate (noncurrent liabilities)		0		0		0		0		0		(191)		0		191		0

Total mark-to-market
	derivative liabilities	$	(13)	$	(1,151)	$	(264)	$	1,315	$	(113)	$	(800)	$	0	$	694	$	(219)

Total mark-to-market
	derivative net assets (liabilities)	$	1,538	$	626	$	24	$	(540)	$	1,648	$	(800)	$	15	$	0	$	863

__________

(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $503 million and $191 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $19 million non current liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above.

(b) Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c) Current and noncurrent assets are shown net of collateral of $338 million and $187 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $15 million and $0 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $540 million at December 31, 2011.

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

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

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+ Details

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

12 Months Ended

Dec. 31, 2012

Debt and Credit Agreements [Abstract]

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

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

Short-Term Borrowings

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

Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2012 and 2011:

	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer		2012 ^(a)		2011 ^(a)		2012		2011	2012		2011
Exelon Corporate	$	500	$	500	$	-	$	161	0.47	%	0.42	%
Generation		5,600		5,600		-		-	0.45	%	0.48	%
ComEd		1,000		1,000		-		-	0.50	%	0.71	%
PECO		600		600		-		-	-		-
BGE		600		400		-		-	0.43	%	0.38	%
Total	$	8,300	$	8,100	$	-	$	161

(a) Equals aggregate bank commitments under revolving and bilateral credit agreements. See discussion below and Credit Agreements table below for items affecting effective program size.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its outstanding commercial paper does not reduce available capacity under a Registrant's credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit agreement.

At December 31, 2012, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements:



							Available Capacity at December 31, 2012
Borrower	Aggregate Bank Commitment^(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper

Exelon Corporate	$	500	$	—	$	2	$	498	$	498
Generation		5,600		—		1,818		3,782		3,782
ComEd		1,000		—		—		1,000		1,000
PECO		600		—		1		599		599
BGE		600		—		—		600		600
Total	$	8,300	$	—	$	1,821	$	6,479	$	6,479

(a) Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd's, PECO's and BGE's service territories. These facilities expire on October 19, 2013 and are solely for issuing letters of credit. As of December 31, 2012, letters of credit issued under these agreements totaled $23 million, $21 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively.

For the year ended December 31, 2012, there were no borrowings under the Registrants' credit facilities.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2012, 2011 and 2010. PECO did not have any short-term borrowings outstanding during 2012, 2011 or 2010.

Exelon

	2012			2011			2010

Average borrowings	$	199		$	218		$	125
Maximum borrowings outstanding		505			600			346
Average interest rates, computed on a daily basis		0.48	%		0.50	%		0.72	%
Average interest rates, at December 31		n.a.			0.44	%		n.a.

Generation
	2012			2011			2010

Average borrowings	$	4		$	51		$	0
Maximum borrowings outstanding		165			304			0
Average interest rates, computed on a daily basis		0.45	%		0.48	%		n.a.
Average interest rates, at December 31		n.a.			n.a.			n.a.

ComEd
	2012			2011			2010

Average borrowings	$	110		$	36		$	125
Maximum borrowings outstanding		366			407			346
Average interest rates, computed on a daily basis		0.50	%		0.71	%		0.72	%
Average interest rates, at December 31		n.a.			n.a.			n.a.

BGE
	2012			2011			2010

Average borrowings	$	6		$	26		$	1
Maximum borrowings outstanding		76			190			46
Average interest rates, computed on a daily basis		0.43	%		0.38	%		0.39	%
Average interest rates, computed at December 31		n.a.			n.a.			n.a.

n.a. Not applicable.

Credit Agreements

In connection with the Upstream Merger, Exelon assumed all of Constellation's obligations under its three-year, unsecured revolving credit facility (the “Constellation Credit Agreement”). Effective as of the Initial Merger, the Constellation Credit Agreement was amended and restated to (1) permit Exelon and Constellation to consummate the Upstream Merger and the restructuring transaction, (2) reduce the aggregate commitments under the Constellation Credit Agreement from $2.5 billion to $1.5 billion, and (3) conform some of the representations, warranties, covenants and events of default in the Constellation Credit Agreement with representations, warranties, covenants and events of default in the Exelon credit agreement, dated as of March 23, 2011, as amended as of the Initial Merger. In connection with the Upstream Merger, Exelon also assumed Constellation's obligations under four separate bilateral credit facilities and a commodity-linked credit facility, which were also amended to conform with the Constellation Credit Agreement effective as of the Initial Merger. Effective as of the Initial Merger, the Exelon Credit Agreement and the Generation Credit Agreement were amended and restated to conform some of the representations, warranties and covenants with provisions of the Constellation Credit Agreement, as amended effective as of the Initial Merger. Exelon Corporation (as successor to Constellation Energy Group) entered into an amendment to the Amended and Restated Credit Agreement dated March 12, 2012, which changed the maturity date to December 31, 2012. See Note 4 — Merger and Acquisitions for further description of the merger transaction.

On August 10, 2012, Exelon Corporate, Generation, PECO and BGE amended and extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, through August 10, 2017. Under these facilities, Exelon Corporate, Generation, PECO and BGE may issue letters of credit in the aggregate of up to $200 million, $3.5 billion, $300 million and $600 million, respectively. Each credit facility permits the applicable borrower to request extensions for up to two additional one-year periods. Each credit facility also allows Exelon Corporate, Generation, PECO and BGE to request increases in aggregate commitments up to an additional $250 million, $1.0 billion, $250 million and $100 million, respectively. Any extension or increase of a credit facility is subject to the approval of the lenders party to that credit facility in their sole discretion. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material.

On March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new unsecured 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 has an initial term expiring on March 28, 2017, and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to replace the credit facility for ComEd were not material.

Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. As of December 31, 2012, Exelon Corporate, Generation, PECO and BGE have adders of up to 27.5, 7.5, 0.0 and 7.5 basis points for prime based borrowings and 127.5, 107.5, 100.0 and 107.5 basis points for LIBOR-based borrowings, respectively. The fee varies depending upon the respective credit ratings of each entity. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The amended covenants in the amended credit facilities are substantially consistent with the covenants in the prior facilities, with the exception of BGE, which replaced its debt to capitalization covenant with an interest coverage ratio.

On October 19, 2012, Generation, ComEd and PECO replaced their expiring minority and community bank credit facilities with new minority and community bank credit facility agreements in the amounts of $50 million, $34 million and $34 million, respectively, and BGE entered into a minority and community bank credit facility in the amount of $5 million. These facilities, which expire in October 2013, are solely utilized by the applicable Registrants to issue letters of credit.

On January 23, 2013, Generation entered into a two year $75 million bilateral letter of credit facility with a bank. This facility will solely be utilized by Generation to issue letters of credit.

An event of default under any of the Registrants' credit facilities would not constitute an event of default under any of the other Registrants' credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit facility would constitute an event of default under the Exelon corporate credit facility.

Each credit facility requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2012:

	Exelon	Generation	ComEd	PECO	BGE

Credit facility threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2012, the interest coverage ratios at the Registrants were as follows:

	Exelon	Generation	ComEd	PECO	BGE

Interest coverage ratio	9.62	14.20	6.14	7.85	5.16

Accounts Receivable Agreement

PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its accounts receivable designated under the agreement in exchange for proceeds of $225 million. As of December 31, 2012 and 2011, the financial institution's undivided interest in PECO's gross accounts receivable was equivalent to $289 million and $329 million, respectively, which represents the financial institution's interest in PECO's eligible receivables as calculated under the terms of the agreement. The agreement requires PECO to maintain eligible receivables at least equivalent to the financial institution's undivided interest. Upon termination or liquidation of this agreement, the financial institution is entitled to recover up to $225 million plus the accrued yield payable from its undivided interest in PECO's receivables. On August 31, 2012, PECO entered into an Amendment to extend this agreement until August 30, 2013. This Amendment also expands the definition of a tariff receivable to include receivables that have been purchased by PECO and paid for in accordance with the Tariff and revises the compliance criteria for the eligible asset test to allow for the payment of capital within a specified period of time. On November 28, 2012, PECO made a principal paydown of $15 million to meet the eligible asset test requirement of the agreement for the October 2012 reporting period. The remaining principal balance of $210 million is classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets. As of December 31, 2012, PECO was in compliance with the requirements of the agreement. In the event the agreement is not further extended, PECO has sufficient short-term liquidity and may seek alternate financing.

Long-Term Debt

On June 18, 2012, Generation issued and sold $775 million of Senior Notes. In connection with this debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $470 million. The interest rate swaps were settled on June 15, 2012 with Generation recording a pre-tax loss of approximately $7 million. The loss was recorded to other comprehensive income within Exelon's and Generation's Consolidated Balance Sheets and is being amortized to income over the life of the related debt as an increase to interest expense.

Concurrently with the new debt issuance, Generation engaged in private offers (the Exchange Offer) to certain eligible holders to exchange any and all of the $700 million outstanding 7.60% Senior Notes due 2032 (Old Notes) of Exelon (which were assumed by Exelon in the merger with Constellation), for:

Generation's newly issued 4.25% Senior Notes due 2022, plus a cash payment; and
Generation's newly issued 5.60% Senior Notes due 2042, plus a cash payment.

On June 28, 2012, pursuant to the Exchange Offer, Generation purchased $441 million of the Old Notes in exchange for issuing $535 million of Notes due in 2022 and 2042, plus a cash payment of approximately $60 million. The $441 million of Old Notes were recorded on Exelon's Consolidated Balance Sheets at $608 million, reflecting a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger which resulted in approximately $13 million gain from the Exchange Offer at Generation. The gain was recorded as an increase to Long-term Debt within Exelon's and Generation's Consolidated Balance Sheets and will be amortized to income over the life of the debt as a reduction in interest expense.

On July 13, 2012, pursuant to the Exchange Offer described above, Generation purchased an additional $1 million of Old Notes in exchange for the Senior Notes due in 2022 and 2042.

In connection with the debt obligations assumed by Exelon as part of the Upstream Merger on March 12, 2012, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation's Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon's Consolidated Balance Sheets. The third-party debt obligations are reported in Long-term Debt on Exelon's Consolidated Balance Sheets. The intercompany loan agreements are summarized as follows:

$700 million aggregate principal amount of Old Notes, $258 million of which was outstanding as of December 31, 2012 after the Exchange Offer described above;
$550 million aggregate principal amount of 4.55% Fixed-Rate Notes due 2015, all of which was outstanding as of December 31, 2012;
$450 million aggregate principal amount of 8.625% Series A Junior Subordinated Debentures due 2063, all of which was outstanding as of December 31, 2012; and
$550 million aggregate principal amount of 5.15% Notes due 2020, all of which was outstanding as of December 31, 2012.

The intercompany loan agreements and the third-party debt obligations described above were increased by $403 million for a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger, of which $199 million was outstanding as of December 31, 2012, primarily reflecting the Exchange Offer described above and amortization of purchase accounting adjustment, which is being amortized over the lives of the arrangements as a reduction to interest expense.

In November 2012, Generation filed a registration statement on Form S-4 to register senior notes to be issued in connection with an exchange offer for the senior notes that were privately issued in June and July 2012. The exchange offer was consummated on February 19, 2013. The registered notes have the same terms and maturity dates as the privately placed senior notes.

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2012 and 2011:

Exelon

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	1.63	%	-	7.63	%	2012-2042	$	7,397	$	7,522
	Unsecured bonds:		2.80	%	-	6.35	%	2013-2036		1,850		—
	Rate stabilization bonds:		5.72	%	-	5.82	%	2017		332		—
	Senior unsecured notes		2.00	%	-	8.63	%	2014-2063		8,021		4,902
	Notes payable and other ^(c)		6.95	%	-	7.83	%	2012-2020		177		174
	Pollution control notes:
		Fixed rates	4.10	%	-	5.00	%	2014-2042		20		46
	Non-recourse debt:
		Fixed rates	2.33	%	-	5.50	%	2031-2037		238		—
		Variable rates	1.96	%	-	2.77	%	2014-2030		262		—

Total long-term debt										18,297		12,644
	Unamortized debt discount and premium, net									(17)		(32)
	Fair value adjustment									448		—
	Fair value hedge carrying value adjustment, net									17		15
	Long-term debt due within one year									(1,047)		(828)

Long-term debt									$	17,698	$	11,799

Long-term debt to financing trusts^(d)
	Subordinated debentures to ComEd Financing III					6.35	%	2033	$	206	$	206
	Subordinated debentures to PECO Trust III					7.38	%	2028		81		81
	Subordinated debentures to PECO Trust IV					5.75	%	2033		103		103
	Subordinated debentures to BGE Trust					6.20	%	2043		258		—

Total long-term debt to financing trusts									$	648	$	390

(a) Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures.

(b) Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.

(c) Includes capital lease obligations of $30 million and $34 million at December 31, 2012 and 2011, respectively. Lease payments of $3 million, $3 million, $3 million, $4 million, $4 million and $13 million will be made in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

(d) Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets.

Generation

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	Senior unsecured notes ^(b)		2.00	%	-	8.63	%	2014-2063	$	6,721	$	3,602
	Pollution control notes:
		Fixed rates	4.10	%	-	5.00	%	2014-2042		20		46
	Non-recourse debt:
		Fixed rates	2.33	%	-	5.50	%	2031-2037		238		—
		Variable rates	1.96	%	-	2.77	%	2014-2030		262		—
	Notes payable and other ^(a)					7.83	%	2012-2020		30		34

Total long-term debt										7,271		3,682
	Fair value adjustment ^(b)									199		—
	Unamortized debt discount and premium, net									13		(5)
	Long-term debt due within one year									(28)		(3)

Long-term debt									$	7,455	$	3,674

(a) Includes Generation's capital lease obligations of $30 million and $34 million at December 31, 2012 and 2011, respectively. Generation will make lease payments of $3 million, $3 million, $3 million, $4 million, $4 million and $13 million in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

(b) Includes $2,007 million of long-term debt to affiliate, comprised of $1,808 million senior unsecured notes and $199 million fair value adjustment.

ComEd

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	1.63	%	-	7.63	%	2012-2042	$	5,447	$	5,547
	Notes payable					6.95	%	2018		140		140

Total long-term debt										5,587		5,687
	Unamortized debt discount and premium, net									(20)		(22)
	Long-term debt due within one year									(252)		(450)

Long-term debt									$	5,315	$	5,215

Long-term debt to financing trust^(c)
	Subordinated debentures to ComEd Financing III					6.35	%	2033	$	206	$	206

(a) Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture.

(b) Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.

(c) Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets.

PECO

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	2.38	%	-	5.95	%	2012-2037	$	1,950	$	1,975

Total long-term debt										1,950		1,975
	Unamortized debt discount and premium, net									(3)		(3)
	Long-term debt due within one year									(300)		(375)

Long-term debt									$	1,647	$	1,597

Long-term debt to financing trusts^(c)
	Subordinated debentures to PECO Trust III					7.38	%	2028	$	81	$	81
	Subordinated debentures to PECO Trust IV					5.75	%	2033		103		103

Long-term debt to financing trusts									$	184	$	184

(a) Substantially all of PECO's assets are subject to the lien of its mortgage indenture.

(b) Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.

(c) Amount owed to this financing trust is recorded as debt to financing trust within PECO's Consolidated Balance Sheets.

BGE

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
		Unsecured bonds	2.80	%	-	6.35	%	2013-2036	$	1,850	$	1,710
		Rate stabilization bonds	5.47	%	-	5.82	%	2012-2017		332	$	395

Total long-term debt										2,182		2,105
	Unamortized debt discount and premium, net									(4)		(4)
	Long-term debt due within one year									(467)		(173)

Long-term debt									$	1,711	$	1,928

Long-term debt to financing trusts^(a)
	Subordinated debentures to BGE Capital Trust II					6.20	%	2043	$	258	$	258

Long-term debt to financing trusts									$	258	$	258

(a) Amount owed to this financing trust is recorded as debt to financing trust within BGE's Consolidated Balance Sheets.

Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2013 through 2017 and thereafter are as follows:

Year	Exelon			Generation		ComEd			PECO			BGE

2013	$	979		$	28	$	252		$	300		$	467
2014		1,483			616		617			250			70
2015		1,613			553		260			—			75
2016		1,041			76		665			—			379
2017		1,462			706		425			—			41
Thereafter		12,367	(a)		5,292		3,574	(b)		1,584	(c)		1,408	(d)

Total	$	18,945		$	7,271	$	5,793		$	2,134		$	2,440

(a) Includes $648 million due to ComEd, PECO and BGE financing trusts.

(b) Includes $206 million due to ComEd financing trust.

(d) Includes $258 million due to BGE financing trust.

Exelon Non-Recourse/Limited-Recourse Debt

The following are descriptions of certain indebtedness of Exelon's project subsidiaries that are outstanding as of December 31, 2012. The indebtedness described below is non-recourse to Exelon, unless otherwise noted.

Antelope Valley Project Development Debt Agreement

The DOE Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project is expected to be completed at the end of 2013. The loan will mature on January 5, 2037. Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity.

On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million. The loan advance terminated the put option that Generation had on the Antelope Valley project. Antelope Valley received additional advances subsequent to the initial advance, and as of December 31, 2012, has received $219 million in DOE-guaranteed funding. See Note 4 - Merger and Acquisitions for additional information on Antelope Valley.

In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2012, Generation had $568 million in letters of credit outstanding related to the project The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made.

In connection with this agreement, Generation entered into a floating-for-fixed interest rate swap with a notional amount of $485 million to mitigate interest rate risk associated with the financing. As Generation received additional loan advances, they subsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps associated with Antelope Valley.

Sacramento PV Energy

In July, 2011, a subsidiary of Generation entered into a $41 million non-recourse project financing supported by a 30MW solar facility in Sacramento, California. As of December 31, 2012, $39 million was outstanding. Borrowings under the facility bear interest at a variable rate, payable quarterly, and are secured by equity interests and assets of the subsidiary. As of December 31, 2012, the subsidiary had interest rate swaps with a notional value of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $39 million facility. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps.

Constellation Solar Horizons Financing

In September 2012, a subsidiary of Generation entered into an 18-year $38 million non-recourse variable interest note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. Borrowing will incur interest at a variable rate, payable quarterly, and are secured by the equity interests and assets of the subsidiary. The subsidiary also executed interest rate swaps for a notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps.

Secured Solar Credit Lending Agreement. A subsidiary of Generation has a three-year senior secured credit facility that is designed to support the growth of solar operations. The amount committed under the facility is $150 million, which may be increased up to $200 million at the subsidiary's request with additional commitments by the lenders. As of December 31, 2012, $113 million was outstanding under the facility with interest payable quarterly. The facility is secured by the equity interests in the subsidiary and the entities that own the solar projects as well as the assets of the subsidiary and the projects' entities. The obligations of the subsidiary are guaranteed by Generation and the projects' entities. The Generation guarantee will terminate upon the subsidiary obtaining a stand-alone investment grade credit rating or the satisfaction of a number of conditions, at which time the financing will become non-recourse to and Generation.

Other Solar Project Financings. Generation has the following amounts outstanding under solar project loan agreements:

• $7 million fully amortizing by June 30, 2031 related to a solar project at the Denver International Airport, and

• $11 million fully amortizing by December 31, 2031 related to a solar project in Holyoke, Massachusetts.

Upstream Gas Property Asset-Based Lending Agreement

Generation has a three year asset-based lending agreement associated with certain upstream gas properties that it owns. The borrowing base committed under the facility is $150 million and can increase to a total of $500 million if the assets support a higher borrowing base and Generation is able to obtain additional commitments from lenders. The facility was amended and extended through July 2016. Borrowings under this facility are secured by the upstream gas properties, and the lenders do not have recourse against Exelon or Generation in the event of a default. As of December 31, 2012, $72 million was outstanding under the facility with interest payable quarterly. The facility includes a provision that requires Generation entities that own the upstream gas properties subject to the agreement to maintain a current ratio of one-to-one. As of December 31, 2012, Generation was in compliant with this provision.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Income Taxes (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Income Taxes (Exelon, Generation, ComEd and PECO)

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

Income tax expense (benefit) from continuing operations is comprised of the following components:

For the Year Ended December 31, 2012		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	37	$	104	$	(40)	$	88	$	(97)
	Deferred		701		326		237		25		101
	Investment tax credit amortization		(11)		(6)		(2)		(2)		(1)
State
	Current		(25)		(12)		6		4		—
	Deferred		(75)		88		38		12		4

	Total	$	627	$	500	$	239	$	127	$	7

For the Year Ended December 31, 2011		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	1	$	431	$	(329)	$	(71)	$	(71)
	Deferred		1,200		435		544		223		130
	Investment tax credit amortization		(12)		(7)		(3)		(2)		(1)
State
	Current		(3)		74		(123)		(37)		—
	Deferred		271		123		161		33		17

	Total	$	1,457	$	1,056	$	250	$	146	$	75

For the Year Ended December 31, 2010		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	506	$	372	$	(203)	$	464	$	(201)
	Deferred		972		635		496		(276)		279
	Investment tax credit amortization		(12)		(7)		(3)		(2)		(1)
State
	Current		171		65		(22)		87		(2)
	Deferred		21		113		89		(121)		22

	Total	$	1,658	$	1,178	$	357	$	152	$	97

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

For the Year Ended December 31, 2012		Exelon (a)		Generation (a)		ComEd		PECO		BGE (b)

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(3.6)		4.7		4.6		2.0		24.3
	Qualified nuclear decommissioning trust fund income	5.4		9.1		—		—		—
	Tax exempt income	(0.2)		(0.4)		—		—		—
	Health care reform legislation	0.1		—		0.4		—		11.6
	Amortization of investment tax credit, net deferred taxes	(1.1)		(1.3)		(0.4)		(0.3)		(8.6)
	Production tax credits and other credits	(2.2)		(3.7)		—		—		—
	Plant basis differences	(2.4)		—		(0.3)		(11.5)		(9.0)
	Merger expenses (c)	2.4		—		—		—		24.2
	Fines and Penalties	2.6		4.4		—		—		—
	Other	(1.1)		(0.5)		(0.6)		(0.2)		(13.9)

Effective income tax rate		34.9	%	47.3	%	38.7	%	25.0	%	63.6	%

For the Year Ended December 31, 2011		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	4.4		4.5		3.6		(0.5)		5.2
	Qualified nuclear decommissioning trust fund income	0.5		0.7		—		—		—
	Domestic production activities deduction	(0.3)		(0.4)		—		—		—
	Tax exempt income	(0.2)		(0.2)		—		—		—
	Health care reform legislation	(0.2)		—		(1.0)		—		(0.5)
	Amortization of investment tax credit	(0.3)		(0.3)		(0.4)		(0.3)		(0.5)
	Production tax credits	(0.9)		(1.2)		—		—		—
	Plant basis differences	(1.0)		—		(0.3)		(6.9)		(2.0)
	Other	(0.2)		(0.7)		0.6		—		(1.7)

Effective income tax rate		36.8	%	37.4	%	37.5	%	27.3	%	35.5	%

For the Year Ended December 31, 2010		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	3.0		3.7		6.3		(4.7)		5.5
	Qualified nuclear decommissioning trust fund income	1.7		2.3		—		—		—
	Domestic production activities deduction	(1.2)		(1.5)		—		—		—
	Tax exempt income	(0.1)		(0.2)		—		—		—
	Health care reform legislation	1.4		0.7		1.4		1.6		1.1
	Amortization of investment tax credit	(0.3)		(0.2)		(0.4)		(0.4)		(0.4)
	Plant basis differences	—		—		(0.1)		0.2		(1.0)
	Uncertain tax position remeasurement	—		(2.0)		9.0		—		—
	Other	(0.2)		(0.4)		0.2		0.2		(0.4)

Effective income tax rate		39.3	%	37.4	%	51.4	%	31.9	%	39.8	%

__________

(a) Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 - December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012 - December 31, 2012.

(b) BGE activity represents the activity for the twelve months ended December 31, 2012, 2011 and 2010.

(c) Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.

The tax effects of temporary differences, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2012 and 2011 are presented below:

For the Year Ended December 31, 2012			Exelon		Generation		ComEd		PECO		BGE

	Plant basis differences		$	(10,689)	$	(3,545)	$	(3,537)	$	(2,437)	$	(1,553)
	Accrual based contracts			(389)		(389)		—		—		—
	Derivatives and other financial instruments			(392)		(479)		(4)		—		—
	Deferred pension and post-retirement obligation			1,225		(439)		(598)		(11)		(12)
	Nuclear decommissioning activities			(604)		(604)		—		—		—
	Deferred debt refinancing costs			(537)		163		(25)		(4)		(4)
	Tax loss carryforward			421		226		32		14		105
	Tax credit carryforward			226		226		—		—		—
	Investment in CENG			(405)		(419)		—		—		—
	Other, net			(25)		9		(33)		150		(186)

Deferred income tax liabilities (net)			$	(11,169)	$	(5,251)	$	(4,165)	$	(2,288)	$	(1,650)
Unamortized investment tax credits				(251)		(216)		(24)		(3)		(6)

Total deferred income tax liabilities (net) and
	unamortized investment tax credits		$	(11,420)	$	(5,467)	$	(4,189)	$	(2,291)	$	(1,656)

For the Year Ended December 31, 2011			Exelon		Generation		ComEd		PECO		BGE

	Plant basis differences		$	(7,803)	$	(2,670)	$	(3,264)	$	(2,238)	$	(1,220)
	Unrealized gains on derivative financial
		instruments		(468)		(737)		(4)		—		—
	Deferred pension and post-retirement obligation			665		(520)		(623)		(31)		(93)
	Nuclear decommissioning activities			(452)		(452)		—		—		—
	Deferred debt refinancing costs			(37)		—		(31)		(6)		(4)
	Other, net			41		338		16		135		(226)

Deferred income tax liabilities (net)			$	(8,054)	$	(4,041)	$	(3,906)	$	(2,140)	$	(1,543)
Unamortized investment tax credits				(200)		(169)		(26)		(5)		(8)

Total deferred income tax liabilities (net) and
	unamortized investment tax credits		$	(8,254)	$	(4,210)	$	(3,932)	$	(2,145)	$	(1,551)

The following table provides the Registrants' carryforwards and any corresponding valuation allowances as of December 31, 2012.

		Exelon			Generation			ComEd		PECO			BGE

Federal
Federal net operating loss	$	635	(a)	$	303		$	91	$	0		$	154
Federal capital loss carryforward		178	(b)		178			0		0			0
Federal general business credits carryforward		226	(c)		226			0		0			0

State
State net operating loss		3,365	(d)		1,649	(f)		0		209	(h)		950	(i)
State capital loss carryforward		127	(e)		119	(g)		0		0			0
Deferred taxes on state tax attributes (net)		187			99			0		14			51
Valuation allowance on state tax attributes		36			35			0		0			1

__________

Exelon's federal net operating loss will expire beginning in 2033
Exelon's federal capital loss carryforwards will expire beginning in 2018
Exelon's federal general business credit carryforwards will expire beginning in 2033
Exelon's state net operating losses will expire beginning in 2014
Exelon's state capital loss carryforwards will expire beginning in 2018
Generation's state net operating losses will expire beginning in 2014
Generation's state capital loss carryforwards will expire beginning in 2018
PECO's state net operating losses will expire beginning in 2032
BGE's state net operating losses will expire beginning in 2026

Tabular reconciliation of unrecognized tax benefits

The following table provides a reconciliation of the Registrants' unrecognized tax benefits as of December 31, 2012, 2011 and 2010:

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2012	$	807	$	683	$	70	$	48	$	11
Merger Balance Transfer		195		183		—		—		—
Increases based on tax positions related to 2012		34		3		—		—		—
Change to positions that only affect timing		(88)		(69)		(3)		(4)		(11)
Increases based on tax positions prior to 2012		91		91		—		—		—
Decreases based on tax positions prior to 2012		(6)		(6)		—		—		—
Decreases related to settlements with taxing authorities		(2)		(2)		—		—		—
Decreases from expiration of statute of limitations		(7)		(7)		—		—		—

Unrecognized tax benefits at December 31, 2012	$	1,024	$	876	$	67	$	44	$	—

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2011	$	787	$	664	$	72	$	44	$	73
Increases based on tax positions related to 2011		5		1		—		4		—
Change to positions that only affect timing		21		24		(2)		—		(62)
Decreases based on tax positions prior to 2011		(3)		(3)		—		—		—
Decrease from expiration of statute of limitations		(3)		(3)		—		—		—

Unrecognized tax benefits at December 31, 2011	$	807	$	683	$	70	$	48	$	11

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2010	$	1,498	$	633	$	471	$	372	$	112
Increases based on tax positions related to 2010		1		—		—		—		—
Decreases based on tax positions related to 2010		(2)		(2)		—		—		—
Change to positions that only affect timing		(262)		55		(3)		(328)		(39)
Increases based on tax positions prior to 2010		8		8		—		—		—
Decreases based on tax positions prior to 2010		(3)		(3)		—		—		—
Decreases related to settlements with taxing authorities		(452)		(26)		(396)		—		—
Decrease from expiration of statute of limitations		(1)		(1)		—		—		—

Unrecognized tax benefits at December 31, 2010	$	787	$	664	$	72	$	44	$	73

Included in Exelon's unrecognized tax benefits balance at December 31, 2012 and 2011 are approximately $730 million and $804 million, respectively, of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.

Unrecognized tax benefits that if recognized would affect the effective tax rate

Exelon and Generation have $294 million and $263 million, respectively, of unrecognized tax benefits at December 31, 2012 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $3 million and $3 million, respectively, of unrecognized tax benefits at December 31, 2011 that, if recognized, would decrease the effective tax rate.

Total amounts of interest and penalties recognized

The following table represents the net interest receivable (payable), including interest related to uncertain tax positions reflected in the Registrants' Consolidated Balance Sheets. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest.

Net interest receivable (payable) as of	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	31	$	(20)	$	107	$	2	$	—
December 31, 2011		74		33		23		28		(1)

The following table sets forth the net interest expense, including interest related to uncertain tax positions, recognized in interest expense (income) in other income and deductions in the Registrants' Consolidated Statements of Operations. The Registrants have not accrued any penalties with respect to uncertain tax positions. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest.

Net interest expense (income) for the years ended	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	(1)	$	11	$	(20)	$	(1)	$	9
December 31, 2011		(56)		(40)		(14)		(1)		(3)
December 31, 2010		110		6		57		35		2

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

Nuclear Decommissioning Liabilities (Exelon and Generation)

AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen's refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. In August 2009, the DOJ filed its answer denying the allegations made by Generation in its complaint. While the discovery phase of the litigation has been completed, no trial date has yet been assigned but could occur sometime in 2013.

During 2012, the parties agreed to take advantage of the court's Alternative Dispute Resolution (ADR) program in an effort to resolve the dispute. The court's ADR program provides a confidential and non-binding mediation process that tries to facilitate settlements. The parties participated in mediation discussions late in 2012 and these discussions are currently ongoing. Due to the possibility of quicker resolution through the ADR program, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

State Income Taxes

Generation has approximately $100 million of unrecognized tax benefits related to various state income tax return positions for which it is reasonably possible the unrecognized tax benefits could significantly change within 12 months due to the expiration of statutes of limitation or settlements with the state taxing authorities. Furthermore, Generation has approximately $55 million of unrecognized tax benefits related to state income tax refund claims that are currently being litigated. It is reasonably possible the unrecognized tax benefits of $55 million would decrease within 12 months.

See Other Tax Matters – Involuntary Conversion, Like Kind Exchange and Competitive Transition Charges section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

Description of tax years that remain subject to examination by major jurisdiction

Taxpayer		Open Years

Exelon (and predecessors) and subsidiaries consolidated Federal income
tax returns		1999-2011
Constellation and subsidiaries consolidated Federal income tax returns		2005-March 2012
Exelon and subsidiaries Illinois unitary income tax returns		2007-2011
Constellation combined New York corporate income tax returns		2008-March 2012
Various separate company Pennsylvania corporate net income tax returns		2008-March 2012
Various separate company Maryland corporate net income tax returns		2005-March 2012

Other Tax Matters

Involuntary Conversion, Like-Kind Exchange and Competitive Transition Charges

1999 Sale of Fossil Generating Assets (Exelon and ComEd). Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the sale of ComEd's fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. Exelon believed that it was economically compelled to dispose of ComEd's fossil generating plants as a result of the Illinois Act and that the proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain could be deferred over the lives of the replacement property under the involuntary conversion provisions. The remaining approximately $1.2 billion of the gain was deferred by reinvesting 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 both positions and asserted that the entire gain of approximately $2.8 billion was taxable in 1999.

Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon contended that the Illinois Act and the Competition Act resulted in the taking of certain of ComEd's and PECO's assets used in their respective businesses of providing electricity services in their defined service areas. Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd's and PECO's transition periods represent compensation for that taking and, accordingly, were excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years.

Status of Involuntary Conversion and CTC Positions. In the second quarter of 2010, the IRS offered to settle the disagreement over the involuntary conversion and CTC positions. Exelon concluded, based on that offer, that it had sufficient new information that a remeasurement of the involuntary conversion and CTC positions was required in accordance with applicable accounting standards. As a result of the required remeasurement, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. In the third quarter of 2010, Exelon and the IRS reached a nonbinding, preliminary agreement to settle Exelon's involuntary conversion on terms consistent with the settlement offer received in the second quarter. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits and established a current tax payable to the IRS. In November 2012, the IRS and Exelon finalized and executed definitive agreements to resolve Exelon's involuntary conversion and CTC positions. Exelon paid $302 million in late 2010 in advance of the final settlement and the assessment.

Status of Like-Kind Exchange Position. 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 $86 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. Exelon expects to initiate litigation in 2013 to contest the IRS's disallowance of the like-kind exchange position. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, as of December 31, 2012, 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 no longer meets the more-likely-than-not standard. As a result, Exelon expects to record in the first quarter of 2013 a non-cash charge to earnings of approximately $270 million, which represents the full amount of interest expense (after-tax) and incremental state tax expense in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $185 million will be recorded at ComEd and the balance at Exelon. Exelon and ComEd will continue to accrue interest on 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. Further, Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd's equity. As a result of this hold harmless agreement, ComEd will record on its consolidated balance sheet 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. The IRS also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position. Exelon continues to believe that it is unlikely that the penalty assertion will ultimately be sustained and therefore no liability for the penalty has been recorded.

This determination for accounting purposes does not alter Exelon's intent to aggressively litigate the issue through appeals, if necessary, which could take three to five years. Exelon currently expects to initiate the litigation in the United States Tax Court, whose decisions are not controlled by the Federal Circuit's decision in Consolidated Edison.

As of March 31, 2013, 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 may be as much as $860 million, of which approximately $320 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.

Accounting for Generation Repairs (Exelon and Generation)

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation's power plants. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. In the second quarter of 2010, Exelon was informed that the IRS intended to issue broad industry guidance with respect to electric generation power plants. In anticipation of the issuance of this guidance, the IRS provided notice to Exelon in the third quarter of 2012 that it intended to apply the principles of Large Business & Industry Directive No. 4-0312-004, thereby deferring auditing Generation's repair deductions until after issuance of the industry guidance and after Exelon has had an opportunity to change its accounting method to conform to that new guidance. As a result, in the third quarter of 2012, Exelon reduced its unrecognized tax benefits by approximately $107 million with an offsetting increase to its deferred tax liabilities and no net impact on results of operations.

The IRS is expected to issue industry guidance during 2013. Exelon and Generation will then determine the financial statement impacts of the generation repair costs accounting method change.

2011 Illinois State Tax Rate Legislation (Exelon, Generation and ComEd)

The Taxpayer Accountability and Budget Stabilization Act, (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 – 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 – 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon reevaluated its deferred state income taxes during the first quarter of 2011. Illinois' corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon's and ComEd's charge is net of a regulatory asset of $15 million.

In 2011, the income tax rate change increased Exelon's Illinois income tax provision (net of Federal taxes) by approximately $7 million, of which $12 million and $5 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $10 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010 and the electric transmission and distribution property repairs deduction discussed below.

Long-Term State Tax Apportionment (Exelon and Generation)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon's and Generation's deferred state income taxes. In 2010, the Registrants performed a review of the long-term state tax rates and noted no significant events that would materially impact state apportionment. As such, there was no update to the long-term state apportionment rates in 2010. In 2011 as a result of the 2011 Illinois State Tax Rate Legislation discussed above, Exelon and Generation re-evaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations. The effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax expense during the first quarter of 2011 of $22 million and $11 million (net of Federal taxes) for Exelon and Generation, respectively. The long-term state tax apportionment also was revised in the fourth quarter of 2011 pursuant to long-term state tax apportionment policy, resulting in recording an additional deferred state tax expense of $1 million and a deferred state tax benefit of $8 million (net of Federal taxes) for Exelon and Generation, respectively.

As a result of the merger with Constellation, Exelon and Generation reevaluated their long-term state tax apportionment in the first quarter of 2012 for all states where they have state income tax obligations, which include Illinois, Maryland and Pennsylvania, as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. The long-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3 million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no change to the long-term state tax apportionment for BGE, ComEd and PECO.

Accounting for Electric Transmission and Distribution Property Repairs (Exelon, Generation, ComEd, PECO and BGE)

On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. ComEd and PECO adopted the safe harbor in the Revenue Procedure for the 2011 and 2010 tax years, respectively. For the year ended December 31, 2011, the adoption of the safe harbor resulted in a $35 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $28 million due to a decrease in its manufacturer's deduction, which are reflected in the effective income tax rate reconciliation above in the plant basis differences and domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoption of the safe harbor resulted in a cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million, $95 million respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million related to a decreased domestic production activities deduction.

BGE adopted the safe harbor for the short period 2012 pre-merger tax year. For the year ended December 31, 2012, the adoption of the safe harbor resulted in a cash tax benefit at BGE in the amount of $27 million.

See Note 3 – Regulatory Matters for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO's cash tax benefit resulting from the application of the method change to years prior to 2010.

Accounting for Gas Distribution Property Repairs (Exelon, PECO and BGE).

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The change to the newly adopted method for the 2011 tax year and 2012 resulted in a tax benefit of $26 million at Exelon, of which $29 million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic production activities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. The IRS is expected to issue industry guidance during 2013. Exelon, PECO and BGE will then determine the financial statement impacts of the gas distribution repair costs accounting method changes.

Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE)

Generation, ComEd and PECO are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2012, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $48 million and $9 million, respectively. During 2012, ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd's 2012 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010. During 2011, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $30 million and $18 million, respectively. During 2011, ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd's 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010 and the electric transmission and distribution property repairs deduction discussed above. During 2010, Generation, ComEd and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $60 million, $2 million and $43 million, respectively.

ComEd received a non-cash contribution to equity from Exelon in 2012 and 2011 of $11 million and $11 million, respectively, related to tax benefits associated with capital projects constructed by ComEd on behalf of Exelon and Generation.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

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

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations [Abstract]

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

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

Nuclear Decommissioning Asset Retirement Obligations

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2011 to December 31, 2012:

		Exelon and Generation
Nuclear decommissioning ARO at January 1, 2011	$	3,276
Accretion expense		209
Net increase due to changes in, and timing of, estimated future cash flows		198
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2011 (a)		3,680
Accretion expense		231
Net increase due to changes in, and timing of, estimated future cash flows		833
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2012 (a)	$	4,741

(a) Includes $10 million and $5 million as the current portion of the ARO at December 31, 2012 and 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

During 2012, Generation's ARO increased by $1,061 million. The increase in the ARO is largely driven by the following four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have dramatically decreased given the current low interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

During 2011, Generation recorded a net increase in the ARO of $ 404 million primarily due to increases for accretion and an increase in the estimated costs to decommission the Oyster Creek and Zion nuclear units resulting from the completion of updated decommissioning cost studies received in 2011 and an increase in the expected long-term escalation rates for energy, partially offset by decreases in long-term escalation rates for labor and other costs as compared to prior study periods. The increase in the Zion nuclear unit ARO resulted in $28 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, as the Zion nuclear unit is retired, and as such, is unable to record increases to the ARO through an ARC. Additionally, the Zion nuclear unit is not subject to a regulatory agreement that would provide for offset of the expense.

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation's transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. On January 7, 2013, EnergySolutions announced that it had entered a definitive acquisition agreement to be acquired by another company. Generation has reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA.

On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. If the plaintiffs prevail on the merits of their claims, some or all of the NDT funds may no longer be available to ZionSolutions for decommissioning Zion Station, in which case, the contractual arrangement would require ZionSolutions to utilize a line of credit to complete the decommissioning. In addition, the appointment of a NDT fund trustee in this matter could impact Generation's future decommissioning activities at other stations by setting a precedent for the appointment of trustees for NDT funds. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. The matter is currently under review by the court.

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 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 to ZionSolutions in Generation 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. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and has a liability of approximately $79 million and $65 million at December 31, 2012 and 2011, respectively, which is included within the nuclear decommissioning ARO. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2012 and 2011:

	Exelon and Generation
	2012		2011
Carrying value of Zion Station pledged assets	$	614	$	734

Payable to Zion Solutions (a)		564		691

Current portion of payable to Zion Solutions (b)		132		128

Withdrawals by Zion Solutions to pay decommissioning costs		192		143

__________

(a) Excludes a liability recorded within 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 Generation's Consolidated Balance Sheets.

ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. 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 and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO currently collects funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are expected to continue through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds. 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 $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 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 collected from ComEd and 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. Generation 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 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. This 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 units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after 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, Generation retains any funds remaining in the NDTs after decommissioning.

At December 31, 2012, and 2011, Exelon and Generation had NDT fund investments totaling $7,248 million and $6,507 million, respectively.

During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investment strategy. At December 31, 2012, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities. At December 31, 2011, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities.

NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation's and Exelon's Consolidated Balance Sheets primarily due to differences in the types of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2012 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2012 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.3% to 6.2% (as compared to a historical 5-year annual average pre-tax return of approximately 3.6%).

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation's ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon's and Generation's cash flows and financial position may be significantly adversely affected.

On March 31, 2011, Generation, in its NRC-required biennial decommissioning funding status report, provided data from which the NRC concluded that the amount of decommissioning funding as of December 31, 2010 for Limerick Unit 1 was less than the amount required by the NRC's regulations. Generation performed the calculations again in early 2012, which reflected that the amount of decommissioning funding as of December 31, 2011, for Limerick Unit 1 was less than the amount required by the NRC's regulations. In February 2012, Generation obtained a parent guarantee in the amount of $115 million to cover the NRC minimum funding assurance requirements for Limerick Unit 1 and informed the NRC that it had addressed the minimum funding issues by, among other things, obtaining the parent guarantee. In a letter dated June 28, 2012, the NRC advised Generation of the NRC's determination that the amount of decommissioning financial assurance provided in Generation's plan was equal to or greater than the minimum required under the NRC regulations and that Generation had provided reasonable assurance that funds would be available for the Limerick Unit 1 decommissioning process.

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 Fund 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 NRC invited Generation to participate in a pre-decisional enforcement conference. At that conference, Generation will have an opportunity to explain its actions to the NRC. Generation will demonstrate that it did not deliberately or intentionally provide inaccurate or incomplete information in violation of the regulations and that it applied the regulatory provisions in a reasonable manner and in good faith. The letter from the NRC does not take issue with Generation's current funding status. The NRC has publicly confirmed that Generation is currently sufficiently funded for decommissioning activities. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation's units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation's obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the value of the NDT fund for any former ComEd unit fall below the amount of the estimated decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon's and Generation's results of operations and financial position could be material. At December 31, 2012, the NDT funds of each of the former ComEd units exceeded the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is the ARO reflected on Generation's Consolidated Balance Sheet at December 31, 2012 and is different, as described above, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Based on the regulatory agreement supported by the PAPUC that dictates Generation's rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon's and Generation's ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon's and Generation's results of operations and financial position could be material.

The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the portions of the Peach Bottom nuclear plants that are not subject to regulatory agreements with respect to the NDT funds are reflected in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, as there are no regulatory agreements associated with these units.

Refer to Note 3 – Regulatory Matters and Note 22 - Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

The following table provides unrealized gains (losses) on NDT funds for 2012, 2011 and 2010:

		Exelon and Generation
		For the Years Ended December 31,
		2012		2011		2010

Net unrealized gains (losses) on decommissioning
	trust funds — Regulatory Agreement Units (a) (b) (c)	$	386	$	(74)	$	294
Net unrealized gains (losses) on decommissioning
	trust funds — Non-Regulatory Agreement Units (c)		105		(4)		104

__________

(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 $73 million and $48 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2012 and 2011. 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 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, which are subject to regulatory accounting, are eliminated within other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income.

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

Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 - Significant Accounting Policies for additional information on the Registrants' accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants' Consolidated Balance Sheets from January 1, 2011 to December 31, 2012:

		Exelon		Generation			ComEd		PECO		BGE

Non-nuclear AROs at January 1, 2011		$	223	$	86	$	105	$	32	$	1
Net decrease due to changes in, and timing of,
	estimated future cash flows (a)		(24)		(3)		(17)		(4)		—
Development projects			7		7		—		—		—
Accretion expense (b)			9		5		3		1		—
Payments			(6)		(3)		(2)		(1)		—

Non-nuclear AROs at December 31, 2011			209		92		89		28		1
Net increase due to changes in, and timing of,
	estimated future cash flows (a)		27		18		8		1		7
Development projects			47		47		—		—		—
Accretion expense(b)			13		8		4		1		—
Merger with Constellation (c)			58		50
Payments			(11)		(8)		(2)		(1)		—

Non-nuclear AROs at December 31, 2012		$	343	$	207	$	99	$	29	$	8

During the year ended December 31, 2011, PECO recorded a reduction in operating and maintenance expense of $3 million. Generation and ComEd did not record any reductions in operating and maintenance expense for the year ended December 31, 2011. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2012.
For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information.

Nuclear Decommissioning (Exelon and Generation)

12 Months Ended

Dec. 31, 2012

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

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

Nuclear Decommissioning Asset Retirement Obligations

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2011 to December 31, 2012:

		Exelon and Generation
Nuclear decommissioning ARO at January 1, 2011	$	3,276
Accretion expense		209
Net increase due to changes in, and timing of, estimated future cash flows		198
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2011 (a)		3,680
Accretion expense		231
Net increase due to changes in, and timing of, estimated future cash flows		833
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2012 (a)	$	4,741

Zion Station Decommissioning

	Exelon and Generation
	2012		2011
Carrying value of Zion Station pledged assets	$	614	$	734

Payable to Zion Solutions (a)		564		691

Current portion of payable to Zion Solutions (b)		132		128

Withdrawals by Zion Solutions to pay decommissioning costs		192		143

__________

(b) Included in other current liabilities within Generation's Consolidated Balance Sheets.

Nuclear Decommissioning Trust Fund Investments

At December 31, 2012, and 2011, Exelon and Generation had NDT fund investments totaling $7,248 million and $6,507 million, respectively.

The following table provides unrealized gains (losses) on NDT funds for 2012, 2011 and 2010:

		Exelon and Generation
		For the Years Ended December 31,
		2012		2011		2010

Net unrealized gains (losses) on decommissioning
	trust funds — Regulatory Agreement Units (a) (b) (c)	$	386	$	(74)	$	294
Net unrealized gains (losses) on decommissioning
	trust funds — Non-Regulatory Agreement Units (c)		105		(4)		104

__________

(c) Net unrealized gains (losses) related to Generation's NDT funds are included within other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

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

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants' Consolidated Balance Sheets from January 1, 2011 to December 31, 2012:

		Exelon		Generation			ComEd		PECO		BGE

Non-nuclear AROs at January 1, 2011		$	223	$	86	$	105	$	32	$	1
Net decrease due to changes in, and timing of,
	estimated future cash flows (a)		(24)		(3)		(17)		(4)		—
Development projects			7		7		—		—		—
Accretion expense (b)			9		5		3		1		—
Payments			(6)		(3)		(2)		(1)		—

Non-nuclear AROs at December 31, 2011			209		92		89		28		1
Net increase due to changes in, and timing of,
	estimated future cash flows (a)		27		18		8		1		7
Development projects			47		47		—		—		—
Accretion expense(b)			13		8		4		1		—
Merger with Constellation (c)			58		50
Payments			(11)		(8)		(2)		(1)		—

Non-nuclear AROs at December 31, 2012		$	343	$	207	$	99	$	29	$	8

During the year ended December 31, 2011, PECO recorded a reduction in operating and maintenance expense of $3 million. Generation and ComEd did not record any reductions in operating and maintenance expense for the year ended December 31, 2011. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2012.
For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information.

Exelon Generation Co L L C [Member]

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

__________

(b) Included in other current liabilities within Generation's Consolidated Balance Sheets.

Nuclear Decommissioning Trust Fund Investments

At December 31, 2012, and 2011, Exelon and Generation had NDT fund investments totaling $7,248 million and $6,507 million, respectively.

Retirement Benefits (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Retirement Benefits [Abstract]

Retirement Benefits (Exelon, Generation, ComEd and PECO)

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

As of December 31, 2012, Exelon sponsored qualified defined benefit pension plans, non-qualified defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's benefit plans and its related assets. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2012.

		Operating Company
Name of Plan:		Generation	ComEd	PECO	BGE	BSC
Qualified Pension Plans:
Exelon Corporation Retirement Program		X	X	X		X
Exelon Corporation Cash Balance Pension Plan		X	X	X		X
Exelon Corporation Pension Plan for
	Bargaining Unit Employees	X	X			X
Exelon New England Union Employees Pension Plan		X
Exelon Employee Pension Plan for Clinton,
	TMI and Oyster Creek	X	X			X
Pension Plan of Constellation Energy Group, Inc.		X			X	X
BG New England Union Employees Pension Plan		X

Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan
	and 2000 Excess Benefit Plan	X	X	X		X
Exelon Corporation Supplemental Management
	Retirement Plan	X	X	X		X
Benefits Restoration Plan of Constellation Energy Group		X			X	X
Senior Executive Supplemental Pension Plan		X			X	X

Other Postretirement Benefit Plans:
PECO Energy Company Retiree Medical Plan		X		X		X
Exelon Corporation Health Care Program		X	X			X
Exelon Corporation Employees' Life Insurance Plan		X	X	X		X
Constellation Energy Group, Inc. Retiree Medical Plan		X			X	X
Constellation Energy Group, Inc. Retiree Dental Plan		X			X	X
Constellation Energy Group, Inc. Life Insurance Plan
	and Family Life Insurance Plan	X			X
BG New England Post-Employment Medical Savings
	Account Plan	X

Exelon's traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying these plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

Benefit Obligations, Plan Assets and Funded Status

Exelon recognizes the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated Other Comprehensive Income (AOCI) and regulatory assets, in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31. The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:

					Other
	Pension Benefits				Postretirement Benefits
	2012		2011		2012		2011
Change in benefit obligation:
Net benefit obligation at beginning of year	$	13,538	$	12,524	$	4,062	$	3,874
Service cost		280		212		156		142
Interest cost		698		649		205		207
Plan participants’ contributions		0		0		34		25
Actuarial loss		1,520		807		313		4
Plan amendments		0		0		(103)		—
Acquisitions/divestitures		1,880				362
Curtailments		(10)		0		(8)		—
Settlements		(169)		0		—		—
Contractual termination benefits		15		0		6		—
Gross benefits paid		(952)		(654)		(219)		(201)
Federal subsidy on benefits paid		—		—		12		11

Net benefit obligation at end of year	$	16,800	$	13,538	$	4,820	$	4,062

Change in plan assets:
Fair value of net plan assets at beginning of year	$	11,302	$	8,859	$	1,797	$	1,655
Actual return on plan assets		1,484		1,003		197		29
Employer contributions		149		2,094		325		277
Plan participants’ contributions		0		0		34		25
Benefits paid ^(a)		(952)		(654)		(218)		(189)
Acquisitions/divestitures		1,543		—		0		—
Settlements		(169)		—		0		—

Fair value of net plan assets at end of year	$	13,357	$	11,302	$	2,135	$	1,797

(a) Exelon's other postretirement benefits paid for the years ended December 31, 2012 and 2011 are net of $1.3 million and $12 million, respectively, of reinsurance proceeds received from the Department of Health and Human Services as part of the Early Retiree Reinsurance Program pursuant to the Affordable Care Act of 2010.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:

						Other
		Pension Benefits				Postretirement Benefits
		2012		2011		2012		2011
Other current liabilities		$	15	$	42	$	23	$	2
Pension obligations			3,428		2,194		—		—
Non-pension postretirement benefit obligations			—		—		2,662		2,263

Unfunded status (net benefit obligation less
	net plan assets)	$	3,443	$	2,236	$	2,685	$	2,265

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets. During the fourth quarter of 2012, Exelon completed an optional lump sum election program for select participants in certain of its qualified pension plans, which reduced the obligation and plan assets associated with those plans. This program decreased pension obligations and plan assets by approximately $425 million and $260 million, respectively, resulting in approximately $165 million overall funded status improvement.

The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.

	PBO in excess of plan assets
	2012		2011

Projected benefit obligation	$	16,800	$	13,538
Fair value of net plan assets		13,357		11,302


	ABO in excess of plan assets
	2012		2011

Projected benefit obligation	$	16,796	$	13,538
Accumulated benefit obligation		15,657		12,616
Fair value of net plan assets		13,353		11,302

On a PBO basis, the plans were funded at 80% at December 31, 2012 compared to 83% at December 31, 2011. On an ABO basis, the plans were funded at 85% at December 31, 2012 compared to 90% at December 31, 2011. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2012, 2011 and 2010 for all plans combined. The table reflects an increase in 2012, and a reduction in 2011 and 2010 of net periodic postretirement benefit costs of approximately $(17) million, $28 million and $38 million, respectively, related to a Federal subsidy provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Modernization Act), discussed further below.

		Pension Benefits						Other Postretirement Benefits
		2012		2011		2010		2012		2011		2010
Components of net periodic benefit
	cost:
Service cost		$	280	$	212	$	190	$	156	$	142	$	124
Interest cost			698		649		660		205		207		214
Expected return on assets			(988)		(939)		(799)		(115)		(111)		(109)
Amortization of:
	Transition obligation		—		—		—		11		9		9
	Prior service cost (credit)		15		14		14		(17)		(38)		(56)
	Actuarial loss		450		331		254		81		66		74
Curtailment charges			—		0		0		(7)		—		—
Settlement charges			31		0		5		—		—		—
Contractual termination benefits (a)			14		—		—		6		—		1

Net periodic benefit cost		$	500	$	267	$	324	$	320	$	275	$	257

ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge.

Through Exelon's postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Medicare Modernization Act, enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon's postretirement benefit plans meets the requirements for the subsidy. See the Health Care Reform Legislation section below for further discussion regarding the income tax treatment of Federal subsidies of prescription drug benefits.

The effect of the subsidy on the components of net periodic postretirement benefit cost for the years ended December 31, 2012, 2011 and 2010 included in the consolidated financial statements was as follows:

	2012		2011		2010

Amortization of the actuarial experience loss	$	(17)	$	3	$	9
Reduction in current period service cost		0		9		10
Reduction in interest cost on the APBO		0		16		19

Total effect of subsidy on net periodic postretirement benefit cost	$	(17)	$	28	$	38

Components of AOCI and Regulatory Assets

Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon's Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets for the years ended December 31, 2012, 2011 and 2010 for all plans combined.

		Pension Benefits						Other Postretirement Benefits
		2012		2011		2010		2012		2011		2010
Changes in plan assets and benefit
	obligations recognized in AOCI
	and regulatory assets:
Current year actuarial (gain) loss		$	1,693	$	744	$	737	$	304	$	74	$	—
Amortization of actuarial gain (loss)			(450)		(331)		(254)		(81)		(66)		(74)
Current year prior service (credit) cost			1		—		—		(109)		—		—
Amortization of prior service (cost)
	credit		(15)		(14)		(14)		17		38		56
Current year transition (asset) obligation			—						1
Amortization of transition asset
	(obligation)		—		—		—		(11)		(9)		(9)
Curtailments			(10)		—		—		(1)		—		—
Settlements			(31)		—		(5)		—		—		—

Total recognized in AOCI and
	regulatory assets ^(a)	$	1,188	$	399	$	464	$	120	$	37	$	(27)

________________

(a) Of the $1,188 million related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $464 million related to pension benefits, $310 million and $154 million were recognized in AOCI and regulatory assets, respectively, during 2010. Of the $(27) million related to other postretirement benefits, $(9) million and $(18) million were recognized in AOCI and regulatory assets, respectively, during 2010.

The following table provides the components of Exelon's gross accumulated other comprehensive loss and regulatory assets that have not been recognized as components of periodic benefit cost at December 31, 2012 and 2011, respectively, for all plans combined:

	Pension Benefits				Other Postretirement Benefits
	2012		2011		2012		2011
Transition obligation	$	—	$	—	$	—	$	11
Prior service cost (credit)		76		90		(107)		(16)
Actuarial loss		7,931		6,729		1,185		963

Total ^(a)	$	8,007	$	6,819	$	1,078	$	958

(a) Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $6,819 million related to pension benefits, $4,311 million and $2,508 million are included in AOCI and regulatory assets, respectively, at December 31, 2011. Of the $958 million related to other postretirement benefits, $475 million and $483 million are included in AOCI and regulatory assets, respectively, at December 31, 2011.

The following table provides the components of Exelon's AOCI and regulatory assets at December 31, 2012 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2013. These estimates are subject to the completion of an actuarial valuation of Exelon's pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2013 and actual claims activity as of December 31, 2012. The valuation is expected to be completed in the first quarter of 2013 for legacy Exelon plans and in the second quarter of 2013 for legacy Constellation plans.

	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	14	$	(19)
Actuarial loss		568		84

Total ^(a)	$	582	$	65

(a) Of the $582 million related to pension benefits at December 31, 2012, $315 million and $267 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $65 million related to other postretirement benefits at December 31, 2012, $29 million and $36 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively.

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon's defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Exelon's expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors.

Expected Rate of Return. In selecting the expected rate of return on plan assets, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon's target asset class allocations.

The following assumptions were used to determine the benefit obligations for all of the plans at December 31, 2012, 2011 and 2010. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year's net periodic benefit costs.

	Pension Benefits			Other Postretirement Benefits
	2012	2011	2010	2012	2011	2010
Discount rate	3.92%	4.74%	5.26%	4.00%	4.80%	5.30%
Rate of compensation increase	(a)	3.75%	3.75%	(a)	3.75%	3.75%
Mortality table	IRS required mortality table for 2013 funding valuation	IRS required mortality table for 2012 funding valuation	IRS required mortality table for 2011 funding valuation	IRS required mortality table for 2013 funding valuation	IRS required mortality table for 2012 funding valuation	IRS required mortality table for 2011 funding valuation
Health care cost trend on covered charges	N/A	N/A	N/A	6.50% decreasing to ultimate trend of 5.00% in 2017	6.50% decreasing to ultimate trend of 5.00% in 2017	7.00% decreasing to ultimate trend of 5.00% in 2015

(a) 3.25% for 2013-2017 and 3.75% thereafter.

The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2012, 2011 and 2010:

Pension Benefits

Other Postretirement Benefits

2012

2011

2010

2012

2011

2010

Discount rate

3.71% (a)

5.26%

5.83%

3.72% (a)

5.30%

5.83%

Expected return on plan assets

7.50% (b)

8.00% (b)

8.50% (b)

6.68% (b)

7.08% (b)

7.83% (b)

Rate of compensation increase

3.75%

4.00%

3.75%

4.00%

Mortality table

IRS required mortality table for 2012 funding valuation

IRS required mortality table for 2011 funding valuation

IRS required mortality table for 2010 funding valuation

IRS required mortality table for 2012 funding valuation

IRS required mortality table for 2011 funding valuation

IRS required mortality table for 2010 funding valuation

Health care cost trend on covered charges

N/A

6.50% decreasing to ultimate trend of 5.00% in 2017

7.00% decreasing to ultimate trend of 5.00% in 2015

7.50% decreasing to ultimate trend of 5.00% in 2015

(a) The initial discount rates used to establish Exelon's pension and other postretirement benefits costs for 2012 were 4.74% and 4.80%, respectively. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates within the indicated ranges. 2012 costs reflect the impact of these remeasurements.

(b) Not applicable to pension and other postretirement benefit plans that do not have plan assets.

Assumed health care cost trend rates have a significant effect on the costs reported for the other postretirement benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

Effect of a one percentage point increase in assumed health care cost trend:
	on 2012 total service and interest cost components	$	81
	on postretirement benefit obligation at December 31, 2012		845
Effect of a one percentage point decrease in assumed health care cost trend:
	on 2012 total service and interest cost components		(56)
	on postretirement benefit obligation at December 31, 2012		(569)

Health Care Reform Legislation

In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer's postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to those offered by Medicare. Although this change did not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Generation, ComEd, PECO and BGE recorded charges of $24 million, $11 million, $9 million and $3 million, respectively. Additionally, as a result of this deductibility change for employers and other Health Care Reform provisions that impact the federal prescription drug subsidy options provided to employers, Exelon has made a change in the manner in which it will receive prescription drug subsidies beginning in 2013.

Additionally, the Health Care Reform Acts also include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of the excise tax on Exelon's other postretirement benefit obligation, including projected inflation rates (based on the CPI) and whether pre- and post-65 retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expected impact in its annual actuarial valuation.

Contributions

The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:

	Pension Benefits						Other Postretirement Benefits
	2012		2011		2010		2012 (a)		2011 (a)		2010 (a)
Generation	$	48	$	954	$	356	$	135	$	121	$	94
ComEd		25		873		260		119		108		60
PECO		13		110		73		33		28		35
BGE (b)		0		0		0		12		0		0
BSC		63		157		77		24		20		14

Exelon	$	149	$	2,094	$	766	$	323	$	277	$	203

(a) The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011, and $10 million, $5 million, $3 million, $2 million and $2 million, respectively, in 2010.

(b) BGE's pension benefit contributions for 2012, 2011, and 2010 exclude $0 million, $54 million, and $197 million, respectively, of pension contributions made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's other postretirement benefit payments for 2012, 2011, and 2010 exclude $4 million, $13 million, and $17 million, respectively, of other postretirement benefit payments made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. These pre-merger contributions are not included in Exelon's financial statements but are reflected in BGE's financial statements.

Exelon plans to contribute approximately $255 million to its qualified pension plans in 2013, of which Generation, ComEd, PECO and BGE will contribute $113 million, $116 million, $11 million and $0 million, respectively. Exelon plans to make non-qualified pension plan benefit payments of approximately $15 million in 2013, of which Generation, ComEd, PECO and BGE will pay $6 million, $1 million, $1 million and $2 million, respectively. Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Additionally, for Exelon's largest qualified pension plan, the projected contributions reflect a funding strategy of contributing the greater of $250 million, which approximates service cost, or the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower minimum pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law will be applied in 2012 while others take effect in 2013. The estimated impacts of the law are reflected in the projected pension contributions.

Unlike the qualified pension plans, Exelon's other postretirement plans are not subject to regulatory minimum contribution requirements. Management considers several factors in determining the level of contributions to Exelon's other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). Exelon expects to contribute approximately $292 million to the other postretirement benefit plans in 2013, of which Generation, ComEd, PECO and BGE expect to contribute $117 million, $114 million, $22 million and $18 million, respectively.

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2012 were:

			Other Postretirement
	Pension Benefits		Benefits
2013	$	943	$	197
2014		807		204
2015		891		212
2016		868		220
2017		902		231
2018 through 2022		5,161		1,330

Total estimated future benefit payments through 2022	$	9,572	$	2,394

Allocation to Exelon Subsidiaries

Generation, ComEd, PECO, and BGE account for their participation in Exelon's pension and other postretirement benefit plans by applying multiemployer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon's corporate restructuring. Exelon allocates the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each participating unit. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Pension and postretirement benefit contributions are allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. For legacy CEG plans, components of pension and other postretirement benefit costs and contributions are allocated to the subsidiaries based on employee participation (both active and retired). Pension assets are allocated such that each subsidiary has a funded status consistent with the overall plan.

The following approximate amounts were included in capital and operating and maintenance expense for the years ended December 31, 2012, 2011 and 2010, respectively, for Generation's, ComEd's, PECO's, BSC's and BGE's allocated portion of the Exelon-sponsored pension and other postretirement benefit plans. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:


For the Year Ended December 31,	Generation		ComEd		PECO		BSC (a)		BGE (b)(c)		Exelon

2012	$	341	$	282	$	50	$	99	$	60	$	820
2011		249		213		32		48		51		542
2010		268		215		46		52		48		581

___________________

These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations.
The amounts included in capital and operating and maintenance expense for the years ended 2012, 2011, and 2010 include $12 million, $51 million, and $48 million, respectively, in costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's capital and operating and maintenance expense for the years ended 2012, 2011, and 2010.
BGE's pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset.

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 an investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. This investment strategy would tend to result in a lower expected rate of return on plan assets in future years. Trust assets for Exelon's other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Exelon used an EROA of 7.50% and 6.45% to estimate its 2013 pension and other postretirement benefit costs, respectively.

Exelon's pension and other postretirement benefit plan target asset allocations and December 31, 2012 and 2011 asset allocations were as follows:

Pension Plans			Percentage of Plan Assets
			at December 31,
Asset Category	Target Allocation		2012		2011

Equity securities	34	%	35	%	32	%
Fixed income securities	40	%	40		47
Alternative investments (a)	26	%	25		21

Total			100	%	100	%

Other Postretirement Benefit Plans			Percentage of Plan Assets
			at December 31,
Asset Category	Target Allocation		2012		2011

Equity securities	45	%	46	%	37	%
Fixed income securities	40	%	40		53
Alternative investments (a)	15	%	14		10

Total			100	%	100	%

(a) Alternative investments include private equity, hedge funds and real estate.

Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans' asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2012. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2012, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Exelon's pension and other postretirement benefit plan assets.

Fair Value Measurements

The following table presents Exelon's pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2012 and 2011:

At December 31, 2012 (a)		Level 1		Level 2		Level 3		Total

Pension plan assets
	Cash equivalents	$	1	$	0	$	0	$	1
	Equity securities:
	Individually held		2,562		0		0		2,562
	Commingled funds		0		1,111		0		1,111
	Mutual funds (c)		323		0		0		323
	Equity securities subtotal		2,885		1,111		0		3,996
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		1,037		0		0		1,037
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		108		0		108
	Foreign debt securities		0		252		0		252
	Corporate debt securities		0		3,330		0		3,330
	Federal agency mortgage-backed securities		0		117		0		117
	Non-Federal agency mortgage-backed securities		0		28		0		28
	Commingled funds		0		274		0		274
	Mutual funds (c)		4		291		0		295
	Derivative instruments (b):
	Assets		0		9		0		9
	Liabilities		0		(21)		0		(21)
	Fixed income securities subtotal		1,041		4,388		0		5,429
	Private equity		0		0		754		754
	Hedge funds		0		1,080		1,235		2,315
	Real estate:
	Individually held		280		0		0		280
	Commingled funds		0		75		0		75
	Real estate funds		0		0		426		426
	Real estate subtotal		280		75		426		781
Pension plan assets subtotal			4,207		6,654		2,415		13,276

Other postretirement benefit plan assets
	Cash equivalents		44		0		0		44
	Equity securities:
	Individually held		198		0		0		198
	Commingled funds		0		530		0		530
	Mutual funds (c)		230		0		0		230
	Equity securities subtotal		428		530		0		958
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		18		0		0		18
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		125		0		125
	Foreign debt securities		0		3		0		3
	Corporate debt securities		0		50		0		50
	Federal agency mortgage-backed securities		0		52		0		52
	Non-Federal agency mortgage-backed securities		0		6		0		6
	Commingled funds		0		271		0		271
	Mutual funds (c)		295		2		0		297
	Fixed income securities subtotal		313		509		0		822
	Private equity		0		0		1		1
	Hedge funds		0		188		12		200
	Real estate:
	Individually held		7		0		0		7
	Commingled funds		0		2		0		2
	Real estate funds		0		6		95		101
	Real estate subtotal		7		8		95		110
Other postretirement benefit plan assets subtotal			792		1,235		108		2,135

Total pension and other postretirement
	benefit plan assets (d) (e)	$	4,999	$	7,889	$	2,523	$	15,411

At December 31, 2011 (a)		Level 1		Level 2		Level 3		Total

Pension plan assets
	Cash equivalents	$	8	$	0	$	0	$	8
	Equity securities:
	Individually held		1,985		0		0		1,985
	Commingled funds		0		858		0		858
	Mutual funds		0		389		0		389
	Equity securities subtotal		1,985		1,247		0		3,232
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		1,616		48		0		1,664
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		88		0		88
	Foreign debt securities		0		224		0		224
	Corporate debt securities		0		2,561		0		2,561
	Federal agency mortgage-backed securities		0		156		0		156
	Non-Federal agency mortgage-backed securities		0		28		0		28
	Commingled funds		0		202		0		202
	Mutual funds		0		277		0		277
	Fixed income securities subtotal		1,616		3,584		0		5,200
	Private equity		0		0		672		672
	Hedge funds (f)		0		0		1,525		1,525
	Real estate:
	Individually held		207		0		0		207
	Commingled funds		0		125		0		125
	Real estate funds		0		0		229		229
	Real estate subtotal		207		125		229		561
Pension plan assets subtotal			3,816		4,956		2,426		11,198

Other postretirement benefit plan assets
	Cash equivalents		73		0		0		73
	Equity securities:
	Individually held		110		0		0		110
	Commingled funds		0		415		0		415
	Mutual funds		0		171		0		171
	Equity securities subtotal		110		586		0		696
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		26		3		0		29
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		93		0		93
	Foreign debt securities		0		4		0		4
	Corporate debt securities		0		41		0		41
	Federal agency mortgage-backed securities		0		34		0		34
	Non-Federal agency mortgage-backed securities		0		7		0		7
	Commingled funds		0		385		0		385
	Mutual funds		0		256		0		256
	Fixed income securities subtotal		26		823		0		849
	Private equity		0		0		1		1
	Hedge funds (f)		0		0		157		157
	Real estate
	Individually held		4		0		0		4
	Commingled funds		0		1		0		1
	Real Estate funds		0		0		7		7
	Real estate subtotal		4		1		7		12
Other postretirement benefit plan assets subtotal			213		1,410		165		1,788

Total pension and other postretirement
	benefit plan assets (d)	$	4,029	$	6,366	$	2,591	$	12,986

See Note 9 - Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy.
Derivative instruments have a total notional amount of $2,498 million and $910 million at December 31, 2012 and 2011, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.
In 2012, Exelon reassessed its policy over the criteria that mutual fund investments must meet in order to be categorized within Level 1 of the fair value hierarchy. Therefore, certain mutual fund investments that were categorized within Level 2 in prior periods have been re-categorized as Level 1 investments as of December 31, 2012. The re-categorization of these mutual fund investments resulted in a transfer out of Level 2 of $852 million.
Excludes net assets of $77 million and $43 million at December 31, 2012 and 2011 respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.
Includes fixed income commingled fund assets of $66 million as of December 31, 2012. The fair value of these fixed income commingled fund assets of $69 million, as of December 31, 2011, are excluded from the tables above.
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion.

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2012 and 2011:


		Hedge funds		Private equity		Real estate		Total

Pension Assets
Balance as of January 1, 2012		$	1,525	$	672	$	229	$	2,426
Actual return on plan assets:
	Relating to assets still held at the reporting date		138		55		24		217
Purchases, sales and settlements:
	Purchases		447		108		134		689
	Sales		(6)		0		0		(6)
	Settlements		(4)		(128)		(28)		(160)
Transfers into (out of) Level 3(a) (b) (c)			(865)		47		67		(751)

Balance as of December 31, 2012		$	1,235	$	754	$	426	$	2,415

Other Postretirement Benefits
Balance as of January 1, 2012		$	157	$	1	$	7	$	165
Actual return on plan assets:
	Relating to assets still held at the reporting date		11		0		3		14
Purchases, sales and settlements:
	Purchases		32		0		91		123
	Sales		0		0		0		0
	Settlements		0		0		(1)		(1)
Transfers into (out of) Level 3 (a) (b) (c)			(188)		0		(5)		(193)

Balance as of December 31, 2012		$	12	$	1	$	95	$	108


		Hedge funds		Private equity		Real estate		Total

Pension Assets
Balance as of January 1, 2011		$	329	$	536	$	179	$	1,044
Actual return on plan assets (d):
	Relating to assets still held at the reporting date		(26)		84		46		104
Purchases, sales and settlements (d):
	Purchases		1,222		121		13		1,356
	Sales		0		0		0		0
	Settlements		0		(69)		(9)		(78)
Transfers into (out of) Level 3			0		0		0		0

Balance as of December 31, 2011		$	1,525	$	672	$	229	$	2,426

Other Postretirement Benefits
Balance as of January 1, 2011		$	5	$	0	$	8	$	13
Actual return on plan assets:
	Relating to assets still held at the reporting date		(3)		0		(1)		(4)
Purchases, sales and settlements:
	Purchases		155		1		0		156
	Sales		0		0		0		0
	Settlements		0		0		0		0
Transfers into (out of) Level 3			0		0		0		0

Balance as of December 31, 2011		$	157	$	1	$	7	$	165

In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's pension plan assets resulting in transfers into Level 3 of $141 million.
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion.
In 2012, the liquidity terms of a certain real estate investment changed to allow redemption within a reasonable period of time from the redemption date which led to a transfer out of Level 3 to Level 2 of $5 million.
Certain prior year amounts have been reclassified for comparative purposes.

Valuation Techniques Used to Determine Fair Value

Cash equivalents. Investments with maturities of three months or less when purchased, including certain short−term fixed income securities and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

Equity securities. With respect to individually held equity securities, including investments in U.S. and international securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually are primarily traded on exchanges that contain only actively traded securities, due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1.

Equity commingled funds and mutual funds are maintained by investment companies that hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross−provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market−based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly−liquid and transparent markets. 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 of similar securities, adjusted for observable differences and are categorized as Level 2.

Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.

Fixed income commingled funds and mutual funds, including short−term investment 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. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.

Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3.

Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or ownership interest of the investments. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock−up period or a gate. For Exelon's investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedge fund investments are categorized as Level 2. For investments that have restrictions that may limit Exelon's ability to redeem the investments at the measurement date or within a reasonable period of time, the hedge fund investments are categorized as Level 3.

Real estate. Real estate investment trusts valued daily based on quoted prices in active markets are categorized as Level 1. Real estate commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. Since these funds are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Other real estate funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, these real estate funds have been categorized as Level 3.

Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE participate in a 401(k) defined contribution savings plan sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon, Generation, ComEd, PECO and BGE match a percentage of the employee contribution up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2012, 2011 and 2010:

For the Year Ended December 31,	Exelon		Generation		ComEd		PECO		BGE

2012	$	67	$	30	$	19	$	7	$	7
2011		78		40		22		9		7
2010		81		42		22		9		6

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 20, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Plant Retirements (Exelon and Generation)

12 Months Ended

Dec. 31, 2012

Corporate Restructuring And Plant Retirements [Abstract]

Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

15. Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

The Registrants provide severance and health and welfare benefits to terminated employees primarily based upon each individual employee's years of service and compensation level. The Registrants accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

The following tables present severance benefits expenses, recorded as operating and maintenance expense in relation to the announced job reductions, for the years ended December 31, 2012, 2011 and 2010:

15. Plant Retirements (Exelon and Generation)

Schuylkill Station and Riverside Station

On October 31, 2012, Generation notified PJM of its intention to permanently retire Schuylkill Generating Station Unit 1 by February 1, 2013, and Riverside Generating Station Unit 6 by June 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, Pennsylvania, which was placed in service in 1958. Riverside Unit 6 is a 115 MW peaking gas/kerosene unit located in Baltimore, Maryland, which was placed in service in 1970. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and declining revenue expectations. On November 30, 2012, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Schuylkill Unit 1 retirement date and as a result, Schuylkill Unit 1 was retired on January 1, 2013. On January 7, 2013, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Riverside Unit 6 retirement date. Exelon will determine the final retirement date for Riverside Unit 6 during the second quarter of 2013. The early retirements will not have a material impact on Generation or Exelon's results of operations, cash flows or financial position.

Oyster Creek

On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.

Eddystone Station and Cromby Station

In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit Generation's retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; Cromby Unit 2 retired on December 31, 2011 and Eddystone Unit 2 retired on May 31, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 is approximately $6 million. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation is reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 operated under the reliability-must-run agreement from June 1, 2011 until their respective retirement dates.

Since the announced retirements in December 2009, Generation recorded pre-tax expense of $44 million, which included $18 million of expense for the write down of inventory, $13 million of expense for estimated salary continuance and health and welfare severance benefits and $13 million of shut down costs recorded within operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

During the year ended December 31, 2012, Generation recorded $1 million of expense for the write down of inventory and $11 million of shut down costs. During the year ended December 31, 2011, Generation recorded pre-tax expense of $4 million for estimated salary continuance and health and welfare severance benefits and $2 million of shut down costs.

The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from January 1, 2011 through December 31, 2012:

Severance Benefits Obligation		Exelon and Generation
Balance at January 1, 2011	$	7

Severance charges recorded		4
Cash payments		(4)

Balance at December 31, 2011		7

Cash payments		(4)

Balance at December 31, 2012	$	3

- Definition

The entire disclosure for restructuring and related activities. Description of restructuring activities such as exit and disposal activities, include facts and circumstances leading to the plan, the expected plan completion date, the major types of costs associated with the plan activities, total expected costs, the accrual balance at the end of the period, and the periods over which the remaining accrual will be settled.

+ References + Details

Preferred Securities (Exelon, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Preferred Securities [Line Items]

Preferred Securities (Exelon, ComEd and PECO)

16. Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)

At December 31, 2012 and 2011, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.

Preferred and Preference Securities of Subsidiaries

At December 31, 2012 and 2011, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.

At December 31, 2012 and 2011, PECO cumulative preferred securities, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below. Shares of preferred securities have full voting rights, including the right to cumulate votes in the election of directors.

			December 31,

	Redemption Price^(a)		2012		2011	2012		2011

				Shares Outstanding			Dollar Amount
Series (without mandatory redemption)
$4.68 (Series D)	$	104.00	150,000		150,000	$	15	$	15
$4.40 (Series C)		112.50	274,720		274,720		27		27
$4.30 (Series B)		102.00	150,000		150,000		15		15
$3.80 (Series A)		106.00	300,000		300,000		30		30

Total preferred securities			874,720		874,720	$	87	$	87

(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.

At December 31, 2012 and 2011, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding amounts set forth below. Shares of BGE preference stock have no voting power except for the following:

The preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE's charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and
Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.

			December 31,

	Redemption Price^(a)		2012		2011	2012		2011

				Shares Outstanding			Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.36	400,000		400,000	$	40	$	40
6.97%, 1993 Series		100.35	500,000		500,000		50		50
6.70%, 1993 Series		100.67	400,000		400,000		40		40
6.99%, 1995 Series		101.05	600,000		600,000		60		60

Total preference stock			1,900,000		1,900,000	$	190	$	190

- Definition

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Common Stock (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Common Stock [Abstract]

Common Stock (Exelon, Generation, ComEd and PECO)

17. Common Stock (Exelon, Generation, ComEd, PECO and BGE)

At December 31, 2012 and 2011, Exelon's common stock without par value consisted of 2,000,000,000 shares authorized and 854,781,389 shares and 663,368,958, shares outstanding, respectively. At December 31, 2012 and 2011, ComEd's common stock with a $ 12.50 par value consisted of 250,000,000 shares authorized and 127,016,761 shares and 127,016,529 shares outstanding, respectively. At December 31, 2012 and 2011, PECO's common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding. At December 31, 2012 and 2011, BGE's common stock without par value consisted of 175,000,000 shares authorized and 1,000 shares outstanding.

ComEd had 74,182 and 75,096 warrants outstanding to purchase ComEd common stock at December 31, 2012 and 2011, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2012 and 2011, 24,727 and 25,032 shares of common stock, respectively, were reserved for the conversion of warrants.

Share Repurchases

Share Repurchase Programs. In April 2004, Exelon's Board of Directors approved a discretionary share repurchase program that allowed Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program was intended to mitigate, in part, the dilutive effect of shares issued under Exelon's employee stock option plan and Exelon's ESPP. The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon's ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The 2004 share repurchase program had no specified limit on the number of shares that could be repurchased and no specified termination date. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon's management.

In the third quarter of 2008, Exelon's Board of Directors approved a share repurchase program for $1.5 billion of its common stock. Subsequently, Exelon's management determined to defer indefinitely any share repurchases. This decision was made in light of a variety of factors, including: developments affecting the world economy and commodity markets, including those for electricity and gas; the continued uncertainty in capital and credit markets and the potential impact of those events on Exelon's future cash needs; projected cash needs to support investment in the business, including maintenance capital and nuclear uprates; and value-added growth opportunities.

Under the share repurchase programs dating back to 2004, 34.7 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2012. During 2012, 2011 and 2010, Exelon had no common stock repurchases.

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, stock options and restricted stock units. At December 31, 2012, there were approximately 20 million shares authorized for issuance under the LTIP. For the years ended December 31, 2012, 2011 and 2010, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

As the LTIP sponsor, Exelon is the sole issuer of all stock-based compensation awards. All awards are recorded as equity or a liability in Exelon's Consolidated Balance Sheets. The stock-based compensation expense specifically attributable to the employees of Generation, ComEd, PECO and BGE is directly recorded to operating and maintenance expense within each of their respective Consolidated Statements of Operations. Stock-based compensation expense attributable to BSC employees is allocated to the Registrants using a cost-causative allocation method.

In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's 1995 Long-Term Incentive Plan, 2002 Senior Management Long-Term Incentive Plan, Amended and Restated 2007 Long-Term Incentive Plan, Amended and Restated Management Long-Term Incentive Plan and Executive Long-Term Incentive Plan (collectively and as amended, if applicable, the "Constellation Plans"). Stock-based awards granted under the Constellation Plans and held by Constellation employees were generally converted into outstanding Exelon stock-based compensation awards with the estimated fair value determined to be $71 million using the Black-Scholes model. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. Specifically, as of the merger closing: (1) Exelon converted 12,037,093 outstanding shares that were subject to Constellation stock options into 11,194,151 Exelon stock options valued at $65 million; and (2) Exelon converted 165,219 Constellation no-sale restricted stock units into 153,654 Exelon no-sale restricted stock units valued at $6 million.

Exelon generally grants most of its stock options in the first quarter of each year. In connection with the merger with Constellation, the Compensation Committee of Exelon's Board of Directors elected to delay the annual equity award grant from January 2012 to the effective date of the merger on March 12, 2012, in order to ensure that a majority of eligible employees receive grants on the same date and at the same market price.

The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:

		Year Ended
		December 31,

Components of Stock-Based Compensation Expense		2012		2011		2010

Performance share awards		$	46	$	26	$	6
Stock options			15		8		10
Restricted stock units			50		31		21
Other stock-based awards			4		4		4

Total stock-based compensation expense included in
	operating and maintenance expense		115		69		41

Income tax benefit			(44)		(27)		(16)

Total after-tax stock-based compensation expense		$	71	$	42	$	25

The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2012, 2011 and 2010:

	Year Ended
	December 31,

Subsidiaries	2012		(a)	2011		2010

Generation	$	42		$	31	$	21
ComEd		11			5		3
PECO		5			5		3
BGE		5			6		4
BSC (b)		52			28		14

Total	$	115		$	69	$	41

(a) For BGE, reflects BGE's stock-based compensation expense for the year ended December 31, 2012. For Exelon and Generation, includes the stock-based compensation expense of Constellation and BGE from the date of the merger, March 12, 2012, through December 31, 2012.

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

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2012, 2011 and 2010.

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon's Consolidated Statements of Cash Flows. The following table presents information regarding Exelon's tax benefits for the years ended December 31, 2012, 2011 and 2010:

			Year Ended
			December 31,

			2012		2011		2010
Realized tax benefit when exercised/distributed:

		Stock options	$	3	$	2	$	5
		Restricted stock units		11		8		9
		Performance share awards		7		7		13
		Stock deferral plan		—		1		1

Excess tax benefits included in other financing activities of Exelon’s
	Consolidated Statements of Cash Flows:
		Stock options	$	2	$	1	$	3

Stock Options

Non-qualified stock options to purchase shares of Exelon's common stock are granted under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options granted under the LTIP generally become exercisable upon a specified vesting date. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

Exelon grants most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2012, 2011 and 2010 were not significant.

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,

	2012			2011			2010

Dividend yield		5.28	%		4.84	%		4.56	%
Expected volatility		23.20	%		24.40	%		27.10	%
Risk-free interest rate		1.30	%		2.65	%		2.96	%
Expected life (years)		6.25			6.25			6.25
Weighted average grant date fair value (per share)	$	4.18		$	6.22		$	8.08

The assumptions above relate to Exelon stock options granted during the period and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended December 31, 2012.

The dividend yield is based on several factors, including Exelon's most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon's common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table presents information with respect to stock option activity for the year ended December 31, 2012:

		Weighted		Weighted
		Average		Average
		Exercise		Remaining
		Price		Contractual	Aggregate
		(per		Life	Intrinsic
	Shares	share)		(years)	Value

Balance of shares outstanding at December 31, 2011	11,553,761	$	48.49
Options granted	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Options exercised	(1,776,041)		26.41
Options forfeited	(980,986)		42.90
Options expired	(459,104)		49.45

Balance of shares outstanding at December 31, 2012	21,903,781	$	45.91	5.58	$	13

Exercisable at December 31, 2012 (a)	19,943,116	$	46.40	5.25	$	13

(a) Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2012, 2011 and 2010:

	Year Ended
	December 31,

	2012		2011		2010

Intrinsic value^(a)	$	19	$	5	$	13
Cash received for exercise price		47		13		24

(a) The difference between the market value on the date of exercise and the option exercise price.

The following table summarizes Exelon's nonvested stock option activity for the year ended December 31, 2012:


		Weighted Average
		Exercise Price
	Shares	(per share)

Nonvested at December 31, 2011 (a)	877,050	$	48.66
Granted (b)	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Vested (b)(c)	(12,023,432)		41.37
Forfeited	(459,104)		49.45

Nonvested at December 31, 2012 (a)	1,960,665	$	40.56

(a) Excludes 2,647,536 and 1,348,000 of stock options issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Includes 8,684,709 of converted Constellation options that were vested prior to the Merger on March 12, 2012.

(c) Includes 1,699,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.

At December 31, 2012, $6 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2.4 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table summarizes Exelon's nonvested restricted stock unit activity for the year ended December 31, 2012:


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	1,074,484	$	48.08
Granted	1,332,214		39.94
Converted Constellation restricted stock	825,735		38.91
Vested	(479,805)		46.36
Forfeited	(76,484)		42.21
Undistributed vested awards (b)	(646,983)		40.75

Nonvested at December 31, 2012 (a)	2,029,161	$	42.12

(a) Excludes 686,121 and 448,827 of restricted stock units issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012.

The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2012, 2011 and 2010 was $39.94, $43.33 and $44.23, respectively. At December 31, 2012 and 2011, Exelon had obligations related to outstanding restricted stock units not yet settled of $58 million and $46 million, respectively, which are included in common stock in Exelon's Consolidated Balance Sheets. For the years ended December 31, 2012, 2011 and 2010, Exelon settled restricted stock units with fair value totaling $25 million, $19 million and $22 million, respectively. At December 31, 2012, $43 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.9 years.

Performance Share Awards

Performance share awards are granted under the LTIP with the 2012 performance share awards being settled in 50% common stock and 50% cash over the three-year vesting term. The 2011 performance share awards are being settled entirely in common stock over the three-year vesting term. The performance shares granted prior to 2011 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period.

These awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock portion is considered an equity award with the 75% payout floor being valued based on Exelon's stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon's current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon's current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established.

In 2010, the number of performance shares granted was determined based on the performance of Exelon's common stock relative to certain stock market indices during the three-year period through the end of the year of grant. These performance share awards generally vest and settle over a three-year period. The holders of these performance share awards receive shares of common stock and/or cash annually during the vesting period. Participants are eligible for partial or full distributions in cash if they meet certain stock ownership requirements.

The 2010 performance share awards that were settled in stock were recorded as common stock within the Consolidated Balance Sheets and recorded at fair value at the date of grant. The grant date fair value of equity classified performance share awards granted during the year ended 2010 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year. This model requires assumptions regarding Exelon's total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon's common stock and all stocks represented in these indices. Volatility for Exelon and all comparable companies is based on historical volatility over one year using daily stock price observation. The 2010 performance share awards that were settled in cash were recorded as liabilities within the Consolidated Balance Sheets. The grant date fair value of liability classified performance share awards granted during the year ended 2010 was based on historical data for the previous two plan years and actual results for the current plan year. The liabilities were remeasured each reporting period throughout the requisite service period and as a result, the compensation costs for cash-settled awards were subject to volatility.

For non retirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method, a method in which the compensation cost is recognized over the requisite service period for each separately vesting tranche of the award as though the award were multiple awards. For performance shares granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period which is the year of grant.

The following table summarizes Exelon's nonvested performance share awards activity for the year ended December 31, 2012:


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	346,848	$	45.37
Granted	1,429,189		39.72
Vested	(167,048)		47.46
Forfeited	(116,388)		39.78
Undistributed vested awards (b)	(179,867)		40.72

Nonvested at December 31, 2012 (a)	1,312,734	$	40.08

(a) Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012.

The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2012, 2011 and 2010 was $39.71, $43.52, and $60.82, respectively. During the years ended December 31, 2012, 2011 and 2010, Exelon settled performance shares with a fair value totaling $23 million, $22 million and $32 million, respectively, of which $3 million, $10 million and $20 million was paid in cash, respectively. As of December 31, 2012, $9 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.2 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:


	December 31,

	2012		2011

Current liabilities^(a)	$	7	$	3
Deferred credits and other liabilities^(b)		11		—
Common stock		35		30

Total	$	53	$	33

(a) Represents the current liability related to performance share awards expected to be settled in cash.

(b) Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share and Equity (Exelon)

12 Months Ended

Dec. 31, 2012

Earnings Per Share and Equity [Abstract]

Earnings Per Share and Equity (Exelon)

18. Earnings Per Share and Equity (Exelon)

Earnings per Share

Diluted earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon's LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	Year Ended December 31,
	2012		2011		2010

Net income on common stock	$	1,160	$	2,495	$	2,563

Weighted average common shares outstanding — basic		816		663		661
Assumed exercise and/or distributions of stock-based awards		3		2		2

Weighted average common shares outstanding — diluted		819		665		663

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 14 million in 2012, 9 million in 2011 and 8 million in 2010.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2012. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

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

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

Nuclear Insurance

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2012, the current liability limit per incident was $12.6 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 October 29, 2008. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of January 1, 2013, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $12.2 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 $117.5 million, payable at no more than $17.5 million per reactor per incident per year. Exelon's maximum liability per incident is approximately $2.2 billion. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $12.6 billion limit for a single incident.

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

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. No distributions were declared in 2011 or 2012. Premiums paid to NEIL by its members are subject to assessment (the retrospective premium obligation) for adverse loss experience. NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of future assessments, or if they will be imposed at all, as of December 31, 2012, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $278 million.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. As of December 31, 2012, Generation's current limit for this coverage is $2.1 billion. For property limits in excess of the first $1.25 billion of that limit, Generation participates in an $850 million single limit blanket policy shared by all the Generation operating nuclear sites and the Salem and Hope Creek nuclear sites. This blanket limit is not subject to automatic reinstatement in the event of a loss. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $220 million per year for losses incurred at any plant insured by the insurance company (the retrospective premium obligation). In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007. The Terrorism Risk Insurance Act expires on December 31, 2014.

Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at an insured nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation's maximum share of any assessment is $58 million per year (the retrospective premium obligation). Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007, as described above.

Effective April 1, 2009, NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

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

Spent Nuclear Fuel Obligation

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation's nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation 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.

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama administration devises a new strategy for long-term SNF management. In early 2010, Secretary of Energy Steven Chu appointed the Blue Ribbon Commission (BRC) on America's Nuclear Future to evaluate and recommend a new plan for managing the back end of the nuclear fuel cycle, including used fuel storage, disposal and fees. The Commission released its final report to the U.S. Energy Secretary on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation's spent nuclear fuel and high-level radioactive waste. The strategy recommended by the Commission encompasses 8 key elements; 1) A new consent-based approach to siting storage and disposal facilities; 2) A new organization to implement the waste management program; 3) Access to utility waste disposal fees for their intended purpose; 4) Prompt efforts to develop a new geological disposal facility; 5) Prompt efforts to develop one or more consolidated storage facilities; 6) Early preparation for the eventual large-scale transport of spent nuclear fuel and high-level waste to consolidated storage and disposal facilities; 7) Support for advances in nuclear energy technology and for workforce development; and 8) Active U.S. leadership in international efforts to address safety, non-proliferation and security concerns.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in 2025.

Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations. The extended delay in SNF acceptance by the DOE has led to Generation's adoption of dry cask storage at its Dresden, Clinton, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle and Quad Cities stations. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2030 and determined that Generation's aggregate nuclear ARO would be increased by approximately $700 million.

In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government's breach, for costs associated with storage of SNF at Generation's nuclear stations pending the DOE's fulfillment of its obligations. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreement, Generation has received cash reimbursements for costs incurred through April 30, 2012, totaling approximately $639 million ($543 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2012, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $61 million, which is recorded within accounts receivable, other. Of this amount, $13 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.

CENG has entered into settlement agreements with the DOE during 2011 and 2012 to recover damages caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Ginna, Calvert Cliffs and Nine Mile Point nuclear power plants. At December 31, 2012, Generation had approximately $22 million recorded as a receivable from CENG with respect to costs incurred by Constellation prior to November 6, 2009, for the Nine Mile Point and Calvert Cliffs nuclear power plants. CENG received the funds for the Nine Mile Point and Calvert Cliffs settlement from the DOE in January 2013 and February 2013, respectively, and remitted the $22 million to Generation.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2012, the unfunded SNF liability for the one-time fee with interest was $1,020 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2012, was 0.127%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The outstanding one-time fee obligations for the Oyster Creek and TMI units remain with the former owners. Clinton has no outstanding obligation. See Note 9 – Fair Value of Assets and Liabilities for additional information.

Energy Commitments

Generation's customer facing activities include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Several of Generation's long-term PPAs, which have been determined to be operating leases, have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants, such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. In addition to physical contracts, Generation uses financial contracts for economic hedging purposes and, to a lesser extent, as part of proprietary trading activities.

Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. Generation provides for delivery of its energy to these customers through firm transmission.

As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreements with CENG were modified to be unit−contingent through the end of their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG's nuclear plants at market prices. Generation discloses in the table below commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 22 — Related Party Transactions for more details on this arrangement.

At December 31, 2012, Generation's short- and long-term commitments, relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following tables:

	Net Capacity			Power-Related			Transmission Rights			Purchased Energy
	Purchases (a)			Purchases (b)			Purchases (c)			from CENG			Total

2013		$	374		$	95		$	28		$	777	$	1,274
2014			353			69			26			516		964
2015			350			25			13			—		388
2016			266			11			2			—		279
2017			203			3			2			—		208
Thereafter			469			5			34			—		508

Total		$	2,015		$	208		$	105		$	1,293	$	3,621

(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at December 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain capacity charges which are contingent on plant availability.

(b) Power-Related Purchases include firm REC purchase agreements. 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.

Pursuant to a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power Company, Inc., dated as of April 17, 2009, Generation agreed to sell its rights to up to 520 MWs, or approximately two-thirds of the capacity, energy and ancillary services supplied under its existing long-term contract with Green Country Energy, LLC. The delivery of power under the PPA commenced June 1, 2012 and will run through February 28, 2022.

ComEd purchases its expected energy requirements through an ICC approved competitive bidding process administered by the IPA, existing ICC approved RFPs, and spot market purchases hedged with a financial swap contract with Generation expiring in 2013. See Note 3—Regulatory Matters for further information.

PECO's long-term PPA with Generation, under which PECO obtained all of its electric supply from Generation for a 12-year period, expired on December 31, 2010. During 2009, 2010, 2011 and 2012, PECO entered into contracts through a competitive procurement process in order to meet a portion of its default service customers' electric supply requirements for 2011 through 2015. See Note 3—Regulatory Matters for further information regarding the DSP Programs.

ComEd is subject to requirements established by the Illinois Settlement Legislation and the Energy Infrastructure Modernization Act related to the use of alternative energy resources. PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. BGE is subject to requirements established by the Public Utilities Article in Maryland related to the use of alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOS procurement auctions have the obligation, by contract with BGE, to meet the RPS requirement. BGE has entered into contracts with curtailment services providers in accordance with the March 2009 MDPSC order. See Note 3—Regulatory Matters for additional information relating to electric generation procurement, alternative energy resources and energy efficiency programs.

ComEd's, PECO's and BGE's electric supply procurement, curtailment services, REC and AEC purchase commitments as of December 31, 2012 are as follows:

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

ComEd
Electric supply procurement(a)	$	1,103	$	367	$	323	$	136	$	137	$	140	$	-
Renewable energy and RECs(b)		1,661		71		73		74		76		82		1,285
PECO
Electric supply procurement(c)		799		561		200		38		-		-		-
AECs		33		12		9		2		2		2		6
BGE
Electric supply procurement(d)		1,401		859		467		75		-		-		-
Curtailment services		153		49		47		41		16		-		-

_________________

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. See Note 3 – Regulatory Matters for additional information.
ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Per the ICC's Final Commission Order on December 19, 2012, the quantities purchased under these long-term renewable contracts should be curtailed during the June 2013 – May 2014 period to avoid exceeding the statutory rate impact for affected customers as a result of an increased number of ComEd's customers purchasing their energy from alternative energy suppliers. See Note 3 – Regulatory Matters for additional information.
PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 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 3 – Regulatory Matters for additional information.
BGE entered into various contracts for the procurement of electricity beginning 2012 through 2015. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 – Regulatory Matters for additional information.

Fuel Purchase Obligations

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation (and with respect to coal, commitments to sell coal). PECO and BGE have commitments to purchase natural gas, related transportation, storage capacity and services to serve customers in their gas distribution service territory. As of December 31, 2012, these net commitments were as follows:

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Generation	$	8,857	$	1,276	$	1,207	$	1,272	$	976	$	1,064	$	3,062
PECO		444		145		87		71		49		15		77
BGE		654		133		73		54		52		52		290

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Exelon	$	716	$	186	$	167	$	114	$	51	$	49	$	149
Generation		487		127		120		94		32		29		85
ComEd		8		2		6		—		—		—		—
PECO		45		17		18		1		1		1		7
BGE		—		—		—		—		—		—		—

Commercial Commitments

Exelon's commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:

				Expiration within
														2018
		Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)		$	1,889	$	1,325	$	—	$	564	$	—	$	—	$	—
Surety bonds^(b)			286		225		—		1		6		4		50
Performance guarantees ^(c)			1,897		908		203		—		—		—		786
Energy marketing contract
	guarantees (d)		8,556		8,556		—		—		—		—		—
Lease guarantees^(e)			48		—		—		—		—		—		48
Middle market lending commitments^(f)			180		180		—		—		—		—		—
Nuclear insurance premiums ^(g)			2,494		—		—		—		—		—		2,494

Total commercial commitments		$	15,350	$	11,194	$	203	$	565	$	6	$	4	$	3,378

(a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c) Performance guarantees - Guarantees issued to ensure performance under specific contracts, including $211 million issued on behalf of CENG nuclear generating facilities for credit support, $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.

(d) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $8.3 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $1.5 billion at December 31, 2012, which represents the total amount Exelon could be required to fund based on December 31, 2012 market prices.

(e) Lease guarantees - Guarantees issued to ensure payments on building leases.

(f) Middle market lending commitments – Represents commitments to investment in loans or managed funds which invest in private companies. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. See Note 9 – Fair Value of Financial Assets and Liabilities for more information on nuclear decommissioning trust funds and middle market lending.

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

Generation's commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	1,841	$	1,278	$	—	$	563	$	—	$	—	$	—
Performance guarantees ^(b)		1,153		907		203		—		—		—		43
Energy marketing contract guarantees^(c)		1,794		1,794		—		—		—		—		—
Middle market lending commitments ^(d)		180		180		—		—		—		—		—
Nuclear insurance premiums ^(e)		2,494		—		—		—		—		—		2,494

Total commercial commitments	$	7,462	$	4,159	$	203	$	563	$	—	$	—	$	2,537

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

(b) Performance guarantees - Guarantees issued to ensure performance under specific contracts including $211 million issued on behalf of CENG nuclear generating facilities for credit support.

(c) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.5 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2012, which represents the total amount Generation could be required to fund based on December 31, 2012 market prices.

(d) Middle market lending commitments – Represents commitments to investment in loans or managed funds which invest in private companies. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. See Note 9 – Fair Value of Financial Assets and Liabilities for more information on nuclear decommissioning trust funds and middle market lending.

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

ComEd's commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		8		8		—		—		—		—		—
Performance guarantees (c)		200		—		—		—		—		—		200

Total commercial commitments	$	230	$	30	$	—	$	—	$	—	$	—	$	200

(a) Letters of credit (non-debt) - ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c) Reflects full and unconditional guarantees of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

PECO's commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		3		3		—		—		—		—		—
Performance guarantees(c)		178		—		—		—		—		—		178

Total commercial commitments	$	203	$	25	$	—	$	—	$	—	$	—	$	178

(a) Letters of credit (non-debt) - PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c) Reflects full and unconditional guarantees of Trust Preferred Securities of PECO Trust III and IV, which is a 100% owned finance subsidiary of PECO.

BGE's commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds (b)		2		2		—		—		—		—		—
Performance guarantees (c)		250		—		—		—		—		—		250

Total commercial commitments	$	254	$	4	$	—	$	—	$	—	$	—	$	250

Letters of credit (non-debt) - BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
Surety bond – Guarantees issued related to contract and commercial agreements, excluding bid bonds.
Reflects full and unconditional guarantees of Trust Preferred Securities of BGE Capital Trust II which is a 100% owned finance subsidiary of BGE.

Construction Commitments

Generation has committed to the construction of a solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with additional phases to come online and an expectation of full commercial operation by the end of the third quarter of 2013. Generation's estimated remaining commitment for the project is $636 million for 2013. See Note 4 - Merger and Acquisitions for additional information.

Refer to Note 3 – Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan, BGE's comprehensive smart grid initiative and ComEd's, PECO's and BGE's commitment to construct transmission facilities under their operating agreements with PJM.

Constellation Merger Commitments

Exelon's commercial and construction commitments shown above do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 4 – Merger and Acquisitions for additional information on the merger commitments.

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2012 were:

	Exelon			Generation			ComEd (b)		PECO (b)		BGE (b)(c)

2013	$	88		$	38		$	13	$	14	$	12
2014		83			38			11		13		10
2015		73			38			11		3		9
2016		69			36			11		3		7
2017		63			36			6		3		6
Remaining years		488			367			57		—		29

Total minimum future lease payments	$	864	(a)	$	553	(a)	$	109	$	36	$	73

(a) Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments.

(b) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd's annual obligation for these arrangements, included in each of the years 2013 - 2017, was $1 million. PECO's annual obligation for these agreements, included in each of the years 2013 - 2017, was $3 million. BGE's annual obligation for these agreements, included in each of the years 2013 - 2017, was $1 million.

The following table presents the Registrants' rental expense under operating leases for the years ended December 31, 2012, 2011 and 2010:

For the Year Ended December 31,	Exelon		Generation (a)		ComEd		PECO		BGE

2012	$	930	$	872	$	18	$	27	$	12
2011		711		659		18		28		15
2010		722		665		19		31		13

(a) Includes Generation's PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation's PPAs and other capacity contracts totaled $801 million, $630 million and $641 million during 2012, 2011 and 2010, respectively.

For information regarding capital lease obligations, see Note 11 – Debt and Credit Agreements.

Indemnifications Related to Sale of Sithe (Exelon and Generation)

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation's sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group's 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy Inc. (Dynegy).

The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2012. Generation believes that it is remote that it will be required to make any additional payments under the guarantee, and currently has no recorded liabilities associated with this guarantee. Generation expects that the exposure covered by this guarantee will expire in 2014. The guarantee is included above in the Commercial Commitments table under performance guarantees.

Indemnifications Related to Sale of TEG and TEP (Exelon and Generation)

On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII's obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII's ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation's maximum obligation under the guarantee is $95 million as of December 31, 2012. Generation believes that it is remote that it will be required to make payments under the guarantee, and has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire in 2013. The guarantee of $95 million is included above in the Commercial Commitments table under performance guarantees.

Environmental Matters

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

ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For many of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location.

ComEd has identified 42 sites, 13 of which have been approved for cleanup by the Illinois EPA or the U.S. EPA and 27 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 2016.
PECO has identified 26 sites, 16 of which have been approved for cleanup by the PA DEP and 10 that 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 2019.

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.

Pursuant to orders from the ICC, PAPUC and MDPSC, respectively, ComEd, PECO and BGE are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are recovering environmental remediation costs of the MGP sites through a provision within customer rates. 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. During the second and third quarters of 2012, ComEd and PECO completed annual studies 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 reserves and regulatory assets by $146 million and $7 million, respectively. BGE assessed its currently and formerly owned gas manufacturing and purification sites quarterly in 2012 and determined that a loss was not probable at ten of its sites as of December 31, 2012. As discussed above, the remediation costs at two of BGE's MGP sites are not considered material. Furthermore, an estimate of a range of possible loss, if any, related to BGE's gas purification site under investigation cannot be determined as of December 31, 2012 given that the site is in the early stages of investigation and any potential contamination is currently unknown. See Note 3 — Regulatory Matters for additional information regarding the associated regulatory assets.

This 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 U.S. EPA. The increase in the reserve at ComEd was predominately tied to 6 sites with a total increase of approximately $111 million. The change was driven by the completion of additional preliminary environmental investigations that identified increases in scope for the remediation of larger areas and to greater depths, along with the requirement for additional groundwater management not previously contemplated in prior studies. ComEd also obtained new information on scope requirements for several sites where another PRP is leading remediation efforts and that ComEd shares responsibility. Prior to completion of any significant clean up, each site remediation plan is approved by the Illinois EPA.

As of December 31, 2012 and 2011, the Registrants have accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

	Total environmental investigation			Portion of total related to MGP
December 31, 2012	and remediation reserve			investigation and remediation

Exelon		$	338		$	298
Generation			30			-
ComEd			260			254
PECO			47			44
BGE			1			-

	Total environmental investigation			Portion of total related to MGP
December 31, 2011	and remediation reserve			investigation and remediation

Exelon		$	224		$	168
Generation			47			-
ComEd			127			121
PECO			50			47
BGE			-			-

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. 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 March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with 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 proposed rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or similar technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry.

In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so−called “non−use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non−use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost−effective. On July 18, 2012, the U.S. EPA announced that it had agreed to extend the court approved Settlement Agreement to extend the deadline to issue a final rule until June 27, 2013. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment.

Oyster Creek. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would have required, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek no later than December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon's determination to cease generation operations no later than December 31, 2019, the NJDEP determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and the limited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, NJDEP determined that the existing measures at the plant represent the best technology available for the facility's cooling water intake through cessation of generation operations.

On December 9, 2010, Generation executed an Administrative Consent Order (ACO) with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster Creek if the conditions of the ACO are satisfied. In accordance with the ACO, on December 21, 2011, the NJDEP agreed to issue a final NPDES permit that became effective on April 12, 2012 that does not require the construction of cooling towers or other closed-cycle cooling facilities. The ACO and the final permit apply only to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon's other plants.

As a result of the decision and the ACO, the expected economic useful life of Oyster Creek was reduced by 10 years to correspond to Exelon's current best estimate as to the timing of ceasing generation operations at the Oyster Creek unit in 2019. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the changes in decommissioning assumptions related to Generation's asset retirement obligation over the remaining expected economic useful life of Oyster Creek.

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.

It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation's other power generation facilities, as well as CENG's, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG.

Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position.

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. Prior to the merger, Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 million to comply with the consent decree. The remaining liability as of December 31, 2012, is approximately $3 million. In addition, a private party has asserted claims relating to groundwater contamination. The company believes that these claims are without merit and is vigorously contesting them.

Alleged Conemaugh Clean Streams Act Violation. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station, violated the Pennsylvania Clean Streams Law. GenOn reached agreement with PA DEP on a proposed Consent Order that was approved by the Commonwealth Court of Pennsylvania on December 4, 2012. Under the Consent Order, GenOn is obligated to pay a civil penalty of $0.5 million, of which Generation's responsibility is approximately $0.2 million.

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. On January 24, 2013, the Court denied petitions for reconsideration of the ruling by the three-judge panel.

Under the CSAPR, Generation units were to receive allowances based on historic heat input, and intrastate and limited interstate trading of allowances was permitted. The CSAPR restricted entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment charge of $57 million on its ARP SO2 allowances that were not expected to be used by Generation's fossil-fuel power plants and that had not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because CSAPR regulations would restrict entirely the use of ARP SO2 allowances beginning in 2012. As of December 31, 2012, Generation had $45 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 cause 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 have challenged MATS in the D.C. Circuit Court, and Exelon was granted permission by the Court to intervene in support of the rule. A decision by the Court is not expected until sometime in 2013. The outcome of the appeal, and its impact on power plant operators' investment and retirement decisions, is uncertain.

Exelon, along with the other co−owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS.

In addition, as of December 31, 2012, Exelon had a $693 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. 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, 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.

National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of the NAAQS by 2014. In December 2012, the U.S. EPA issued a more stringent particulate matter NAAQS. The Agency is currently evaluating its 2008 ozone NAAQS for potentially more stringent requirements as was previously recommended by the U.S. EPA Clean Air Act Scientific Advisory Committee (CASAC) when it reviewed the 2008 ozone NAAQS (that is currently the subject of litigation in the D.C. Circuit Court). These final and pending NAAQS reviews could result in more stringent emissions limits on fossil-fired electric generating stations. In July 2012, the D.C. Circuit Court issued separate rules upholding tightened NAAQS established by the U.S. EPA in 2010 for nitrogen dioxide and sulfur dioxide. The rulings clear the way for the U.S. EPA to continue work already underway with state and local agencies on implementing revised SIP's designed to achieve or maintain the required air quality levels. To the extent not already impacted by CAIR (and in the future by CSAPR after revision upon remand) and MATS, some power plants could be required to achieve further reductions of nitrogen dioxide and sulfur dioxide emissions.

In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in 2014. Litigation of the ozone standard in the D.C. Circuit Court continues. 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. It is unclear if the vacatur of the CSAPR, one of the regulations that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA's view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020.

In addition to these NAAQS, the U.S. EPA also expects to finalize initial designations for the 2010 one-hour SO2 standard in June 2013 and require states to submit state implementation plans (SIPs) for nonattainment areas by February 2015. Compliance with the one-hour SO2 standard is required by February 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the U.S. EPA's final one-hour SO2 standard designation methodology at this point in time as the U.S. EPA continues to consider whether to used modeled or monitored data to inform the designation process, nor potential SIP requirements for areas found to be in nonattainment.

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.

On August 6, 2007, ComEd received a NOV addressed to it and Midwest Generation from the U.S. EPA, alleging, in relevant part, that ComEd and Midwest Generation violated and are continuing to violate provisions of the Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since their purchase from ComEd in 1999. In August 2009, the United States and the State of Illinois filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to most of the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon was named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation's partial motion to dismiss all but one of the claims against Midwest Generation. The District Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation's ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint against Midwest Generation asserting claims substantially similar to those in the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd. On March 16, 2011, the District Court granted ComEd's motion to dismiss the May 2010 complaint in its entirety as it relates to ComEd. On January 3, 2012, upon leave of the District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals for the Seventh Circuit. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the amended complaint, however, Exelon, Generation and ComEd have concluded that, in light of the March 2011 District Court decision, the likelihood of loss is remote. Therefore, no reserve has been established.

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

As a result of the bankruptcy filing, Exelon and Generation have recorded liabilities and receivable reserves as of December 31, 2012, for a total of $13 million, which consists primarily of lease payments under a coal rail car lease and estimated payments for asbestos personal injury claims filed pre-Petition Date. The Bankruptcy Court approved the rejection of the agreement under which Midwest Generation was responsible for obligations under the lease, leaving Generation as the party responsible to make remaining payments under the lease. Exelon and Generation currently expect Midwest Generation or its successor will remain responsible for asbestos personal injury claims filed post-Petition Date, and as such have recorded no liability for such amounts. Requirements for Generation to ultimately satisfy such claims could have a material adverse impact on Exelon's and Generation's future results of operations.

As of the Petition Date, Generation had wholesale power transactions with Edison Mission Marketing and Trading, an affiliate of Midwest Generation not included in the bankruptcy proceeding. Generation expects these transactions to be fully settled in the normal course.

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 the 2001 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 requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors, including the impact of Midwest Generation's bankruptcy. Additionally, the obligations of EME and Midwest Generation to ComEd under the sale agreement, including the environmental indemnity, may be discharged in the bankruptcy proceeding. In such circumstances, ComEd (and Generation, through ComEd) may only have an unsecured claim against EME and Midwest Generation for the environmental remediation costs that would have otherwise been obligations of EME and Midwest Generation under the sale agreement. This unsecured claim may yield a fractional, or possibly no, recovery for ComEd and Generation.

ComEd and Generation continue to monitor the bankruptcy proceedings and available public information as to potential environmental exposures regarding the Midwest Generation plant sites. Midwest Generation publicly disclosed in its third quarter 2012 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 four 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 Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any such exposures. Further, Midwest Generation's reorganization process will likely extend beyond one year and the outcome is uncertain, including whether the facilities will continue to operate and the identity or financial wherewithal of potential future plant owners. 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 no liability has been recorded at December 31, 2012. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows.

Solid and Hazardous Waste

Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon's 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. 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 SFS that could take up to one year to complete, and it is unknown when the U.S. EPA will propose a remedy for public comment. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRP's 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 2013 so that settlement discussions could proceed. Based on Exelon's preliminary review, it appears probable that Exelon 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”). The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the 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 was subsequently granted. On October 23, 2012, a third lawsuit was filed in the same court on behalf of three additional plaintiffs against Cotter and seven other defendants, but not Exelon. The allegations in that complaint mirror the two previously-filed lawsuits. It is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. Due to the early stage of the litigation, Exelon cannot estimate a range of loss, if any.

68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean−up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean−up options. The potentially responsible parties 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. The U.S. EPA is expected to make a final selection of one of the alternatives in 2013. Based on Exelon's preliminary review, it appears probable that Exelon has liability and has established an appropriate accrual for its share of the estimated clean−up costs. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean−up of the site.

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, MD. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. The letter provided 60 days for the PRPs to decide whether or not to participate in the investigation. 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 July 30, 2012, BGE along with the three other named PRP's provided the U.S. EPA with a “Good Faith Offer” along with a proposed Settlement Agreement to conduct a Remedial Investigation and a Feasibility Study at the Site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The PRPs will seek to reach agreement with the U.S. EPA to conduct the investigation. 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 Tailoring Rule based on petitioners' lack of standing. Further, in the same decision, the court denied all challenges to the U.S. EPA's endangerment finding, and the Agency's “Tailpipe Rule” for cars and light trucks. In August 2012, several industry parties filed petitions for an en banc rehearing of the Agency's GHG regulations with the D.C. Circuit court. On September 6, 2012, the Circuit Court ordered the U.S. EPA, intervening groups, and some states to reply to the industry petitions.

On April 13, 2012, the U.S. EPA published proposed regulations for NSPS for GHG emissions from new fossil fuel power plants, greater than 25 MW, that would require the plants to limit CO2 emissions to a thirty year average of less than 1,000 pounds per MWh (less than 1,800 pounds per MWh for the first ten years and less than 600 pounds per MWh thereafter). 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. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants. The U.S. EPA is also expected to establish in 2013 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act.

Litigation and Regulatory Matters

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

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

At December 31, 2012 and 2011, Generation had reserved approximately $63 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2012, approximately $14 million of this amount related to 170 open claims presented to Generation, while the remaining $49 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 2012, Generation increased its reserve by approximately $19 million, primarily due to increased actual and projected number and severity of claims. During 2011 and 2010, the updates to this reserve did not result in material adjustments.

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 480 individuals who were never employees of BGE or Generation 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 Generation in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Generation 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 once they are placed on the trial docket. At present, none of the pending cases are set for trial. Given the limited discovery, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:

the identity of the facilities at which the plaintiffs allegedly worked as contractors;
the names of the plaintiffs' employers;
the dates on which and the places where the exposure allegedly occurred; and
the facts and circumstances relating to the alleged exposure.

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

Federal Energy Regulatory Commission Investigation (Exelon and Generation).

On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation's power trading activities in and around the ISO-NY from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay a $135 million civil penalty and $110 million in disgorgement. The disgorgement amount will be disbursed in two ways. First, Constellation will provide $1 million each to six U.S. regional grid operators for the purpose of improving their surveillance and analytic capabilities. The remainder of the disgorgement amount was deposited in a fund that will be administered by a FERC ALJ. State agencies in New York, New England and PJM (the regional grid operator for 13 states and the District of Columbia) will be eligible to make claims against the fund on behalf of electric energy consumers in those states.

During the year ended December 31, 2012, Generation recorded expense of $195 million in operating and maintenance expense with the remaining $50 million recorded as a Constellation pre-acquisition contingency. As of December 31, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 4 — Merger and Acquisitions for additional information on the merger.

Continuous Power Interruption (ComEd)

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). The ICC is currently conducting a proceeding to assess ComEd's request. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non−consequential damages, and the local governments in the areas in which those customers are located could seek recovery of emergency and contingency expenses.

On January 25, 2013 the ALJ issued a Proposed Order in the Summer 2011 Storm Docket. The ALJ found that a complete waiver of liability should apply for five of the six storms at issue, and found that for the July 2011 storm, 34,599 interruptions were preventable and therefore no waiver should apply. The ALJ also found that ComEd's system is designed, constructed and maintained in accordance with good utility practice, thereby rejecting a request by the Illinois Attorney General for the ICC to open an investigation.

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 January 10, 2013, the ALJ issued a Proposed Order in the February 2011 Blizzard Docket, finding that a complete waiver of liability should apply for the storm. As with the Summer 2011 Storm Docket, the ALJ found that ComEd's system is designed, constructed and maintained in accordance with good utility practice.

The ultimate outcomes of these proceedings are uncertain, and the amount of damages, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows.

Securities Class Action (Exelon)

Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation's June 27, 2008 offering of the Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements, including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10−Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Exchange Act of 1934 and limiting the suit to those persons who purchased Debentures in the June 2008 offering. In August 2011, plaintiffs requested permission from the court to file a third amended complaint in an effort to attempt to revive the claims of the common shareholders. Constellation filed an objection to the plaintiffs' request for permission to file a third amended complaint and, on March 28, 2012, the District Court of Maryland denied the plaintiffs' request for permission to revive the claims of the common shareholders. Given that limited discovery has occurred, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, Exelon is unable at this time to provide an estimate of the range of reasonably possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on its financial results.

Fund Transfer Restrictions (Exelon, ComEd, PECO and BGE)

Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon's intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon's actual cash needs.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

PECO's Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. At December 31, 2012, such capital was $3.0 billion and amounted to about 34 times the liquidating value of the outstanding preferred securities of $87 million. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

BGE pays dividends on its common stock after its Board of Directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE's preference stock have not been paid.

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

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

Income Taxes

See Note 12—Income Taxes for information regarding the Registrants' income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Supplemental Financial Information [Abstract]

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

20. 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 for the years ended December 31, 2012, 2011 and 2010.

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	463	$	82	$	239	$	141	$	75
Property		227		189		22		13		111
Payroll		131		78		26		12		18
Other		198		20		8		(4)		4

Total taxes other than income	$	1,019	$	369	$	295	$	162	$	208

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	443	$	27	$	243	$	173	$	79
Property		177		146		22		9		107
Payroll		123		71		25		13		17
Other		42		20		6		10		4

Total taxes other than income	$	785	$	264	$	296	$	205	$	207

For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	476	$	0	$	205	$	271	$	79
Property		175		142		20		13		102
Payroll		121		70		24		12		16
Other		36		18		7		7		3

Total taxes other than income	$	808	$	230	$	256	$	303	$	200

(a) Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations.

For the Year Ended December 31, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	189	$	189	$	0	$	0	$	0
		Non-Regulatory Agreement Units		102		102		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		386		386		0		0		0
		Non-Regulatory Agreement Units		105		105		0		0		0
	Net unrealized gains on pledged assets —
		Zion Station decommissioning		73		73		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(530)		(530)		0		0		0
Total decommissioning-related activities				325		325		0		0		0
Investment income				20		3		1		2		11	(c)
Long-term lease income				29		0		0		0		0
Interest income related to uncertain income tax positions				15		2		20		0		0
AFUDC - Equity				17		0		6		4		10
Credit facility termination fees				(85)		(85)		0		0		0
Other				25		(6)		12		2		2

Other, net			$	346	$	239	$	39	$	8	$	23

For the Year Ended December 31, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	177	$	177	$	0	$	0	$	0
		Non-Regulatory Agreement Units		45		45		0		0		0
	Net unrealized losses on decommissioning trust funds —
		Regulatory Agreement Units		(74)		(74)		0		0		0
		Non-Regulatory Agreement Units		(4)		(4)		0		0		0
	Net unrealized gains on pledged assets —
		Zion Station decommissioning		48		48		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(130)		(130)		0		0		0
Total decommissioning-related activities				62		62		0		0		0
Investment income				10		1		1		3		13	(c)
Long-term lease income				28		0		0		0		0
Interest income related to uncertain income tax positions				53		31		14		1		0
AFUDC - Equity				17		0		8		9		15
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				(3)		(8)		6		1		(2)

Other, net			$	203	$	122	$	29	$	14	$	26

For the Year Ended December 31, 2010			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	176	$	176	$	0	$	0	$	0
		Non-Regulatory Agreement Units		51		51		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		316		316		0		0		0
		Non-Regulatory Agreement Units		104		104		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(394)		(394)		0		0		0
Total decommissioning-related activities				253		253		0		0		0
Investment income				1		0		0		1		15	(c)
Long-term lease income				27		0		0		0		0
Interest income related to uncertain income tax positions				0		0		6		0		0
AFUDC - Equity				11		0		4		7		10
Realized gain on Rabbi trust investments				1		0		1		0		0
Other				19		4		13		0		0

Other, net			$	312	$	257	$	24	$	8	$	25

(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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 3 – Regulatory Matters for additional information regarding the rate stabilization deferral. )

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants' Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010.

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,712	$	733	$	525	$	207	$	245
Regulatory assets		129		0		80		10		53
Amortization of intangible assets, net		40		35		5		0		0
Amortization of energy contract assets and liabilities(a)		1,110		1,110		0		0		0
Nuclear fuel(a)		848		848		0		0		0
ARO accretion(b)		240		240		0		0		0

Total depreciation, amortization and accretion	$	4,079	$	2,966	$	610	$	217	$	298

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,284	$	570	$	502	$	191	$	224
Regulatory assets		63		0		52		11		50
Nuclear fuel(a)		755		755		0		0		0
ARO accretion(b)		214		214		0		0		0

Total depreciation, amortization and accretion	$	2,316	$	1,539	$	554	$	202	$	274

For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO			BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,144	$	474	$	473	$	171		$	214
Regulatory assets		931		0		43		889	(c)		35
Nuclear fuel(a)		672		672		0		0			0
ARO accretion(b)		196		195		1		0			0

Total depreciation, amortization and accretion	$	2,943	$	1,341	$	517	$	1,060		$	249

(a) Included in revenues or fuel expense on the Registrants' Consolidated Statements of Operations.

(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations.

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	761	$	286	$	288	$	113	$	136
Income taxes (net of refunds)		(171)		175		(42)		(64)		(112)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	820	$	341	$	282	$	50	$	57
Loss in equity method investments		91		91		0		0		0
Provision for uncollectible accounts		164		22		42		60		44
Provision for obsolete inventory		6		6		1		0		0
Stock-based compensation costs		94		0		0		0		0
Other decommissioning-related activity (a)		(145)		(145)		0		0		0
Energy-related options (b)		160		160		0		0		0
Amortization of regulatory asset related to debt costs		18		0		13		3		2
Amortization of rate stabilization deferral		57		0		0		0		67
Amortization of debt fair value adjustment		(34)		(34)		0		0		0
Merger-related commitments (d)		141		32		0		0		27
Severance cost		99		34		0		0		0
Discrete impacts from Energy Infrastructure
Modernization Act (EIMA) (c)		(96)		0		(96)		0		0
Amortization of debt costs		19		11		5		3		2
Other		(11)		19		5		9		(6)

Total other non-cash operating activities	$	1,383	$	537	$	252	$	125	$	193

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	71	$	0	$	28	$	20	$	26
Other regulatory assets and liabilities		(404)		0		(68)		18		(112)
Other current assets		213		(30)		(7)		(12)		(7)
Other noncurrent assets and liabilities		(248)		(98)		(95)		(10)		8

Total changes in other assets and liabilities	$	(368)	$	(128)	$	(142)	$	16	$	(85)

	Exelon		Generation			ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	781	$	781		$	2	$	0	$	0
Change in capital expenditures not paid		160		103	(e)		15		26		(4)
Merger with Constellation, common stock issued		7,365		5,264			0		0		0

(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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(c) Includes the regulatory asset, pursuant to EIMA, which represents the ICC's approved distribution formula and associated rulings as of December 31, 2012 and ComEd's best estimate of the probable increase in distribution rates to provide recovery of prudent and reasonable costs incurred for the 12 months ended December 31, 2012.

(d) See Note 4 – Mergers and Acquisitions for more information on merger-related commitments.

(e) Includes $247 million of capital expenditures not paid as of December 31, 2012 related to Antelope Valley.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2012 and 2011.

December 31, 2012		Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
	Financing trusts^(a)	$	22	$	0	$	6	$	8	$	8
	Keystone Fuels, LLC		38		38		0		0		0
	Conemaugh Fuels, LLC		26		26		0		0		0
	CENG		1,849		1,849		0		0		0
	Safe Harbor		293		293		0		0		0
	Malacha		8		8		0		0		0
	Other investments		34		33		0		0		0

	Total equity method investments		2,270		2,247		6		8		8

Other investments:
	Net investment in direct financing leases		685		0		0		0		0
	Employee benefit trusts and investments^(b)		100		22		8		22		5

Total investments		$	3,055	$	2,269	$	14	$	30	$	13

December 31, 2011		Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
	Financing trusts^(a)	$	15	$	0	$	6	$	8	$	8
	Keystone Fuels, LLC		13		13		0		0		0
	Conemaugh Fuels, LLC		16		16		0		0		0
	Sacramento Solar		1		1		0		0		0

	Total equity method investments		45		30		6		8		8

Other investments:
	Net investment in direct financing leases		656		0		0		0		0
	Employee benefit trusts and investments^(b)		65		11		21		22		0

Total investments		$	766	$	41	$	27	$	30	$	8

(a) Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the Consolidated Balance Sheets. See Note 1 - Significant Accounting Policies for additional information.

(b) The Registrants' investments in these marketable securities are recorded at fair market value.

December 2010 IRS Payment (Exelon). In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon's involuntary conversion and CTC positions. In order to stop additional interest from accruing on the expected assessment resulting from the agreement, Exelon paid $302 million to the IRS on December 28, 2010. As of December 31, 2010, Exelon had not funded the specific bank account from which the IRS payment was disbursed resulting in a current liability. This amount was subsequently funded in January 2011. Under the authoritative guidance for offsetting balances, Exelon included this payment in Cash and cash equivalents with an offsetting amount in Other current liabilities on its Consolidated Balance Sheets. See Note 12 - Income Taxes for additional information.

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 passive generating station leases with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. 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 require the lessees to return the leasehold interests or to arrange a service contract with a third party for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. 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. At December 31, 2012 and 2011, the components of the net investment in long-term leases were as follows:

	December 31,

	2012		2011

Estimated residual value of leased assets	$	1,492	$	1,492
Less: unearned income		807		836

Net investment in long-term leases	$	685	$	656

The following tables provide additional information about liabilities of the Registrants at December 31, 2012 and 2011.

December 31, 2012		Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)		$	708		$	371		$	125	$	45	$	38
Taxes accrued			353			247			61		3		22
Interest accrued			236			60			96		32		41
Severance accrued			91			42			4		1		5
Other accrued expenses			412	(b)		396	(b)		9		1		-

Total accrued expenses		$	1,800		$	1,116		$	295	$	82	$	106




December 31, 2011		Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)		$	520		$	264		$	127	$	48	$	42
Taxes accrued			297			241			59		5		26
Interest accrued			192			56			124		27		41
Severance accrued			15			9			2		1		-
Other accrued expenses			231	(b)		209	(b)		6		2		1

Total accrued expenses		$	1,255		$	779		$	318	$	83	$	110


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
(b)	Includes $327 million and $184 million for amounts accrued related to Antelope Valley as of December 31, 2012 and December 31, 2011, respectively.

Accumulated Other Comprehensive Income (Loss)

The following tables provide information about accumulated OCI income (loss) recorded (after tax) within Exelon's Consolidated Balance Sheets at December 31, 2012 and 2011:

December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	367	$	513	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(3,155)		(19)		0		0		0
Unrealized loss on marketable securities		21		19		0		1		0

Total accumulated other comprehensive income (loss)	$	(2,767)	$	513	$	0	$	1	$	0

December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	488	$	915	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(2,938)		0		0		0		0
Unrealized loss on marketable securities		0		0		(1)		0		0

Total accumulated other comprehensive income (loss)	$	(2,450)	$	915	$	(1)	$	0	$	0

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	649	$	158	$	296	$	128	$	122
Income taxes (net of refunds)		(457)		347		(676)		(65)		(54)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	542	$	249	$	213	$	32	$	51
Provision for uncollectible accounts		121		0		57		64		44
Stock-based compensation costs		67		0		0		0		0
Other decommissioning-related activity (a)		16		16		0		0		0
Energy-related options (b)		137		137		0		0		0
Amortization of regulatory asset related to debt costs		21		0		18		3		2
Amortization of rate stabilization deferral		0		0		0		0		57
Deferral of storm costs		0		0		0		0		(16)
Uncollectible accounts recovery, net		14		0		14		0		0
Discrete impacts from 2010 Rate Case order (c)		(32)		0		(32)		0		0
Bargain purchase gain related to Wolf Hollow Acquisition		(36)		(36)		0		0		0
Discrete impacts from Energy Infrastructure
Modernization Act (EIMA) (d)		(82)		0		(82)		0		0
Other		2		55		(4)		1		(9)

Total other non-cash operating activities	$	770	$	421	$	184	$	100	$	129

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(45)	$	0	$	(49)	$	4	$	(52)
Other regulatory assets and liabilities		0		0		44		26		10
Other current assets		(101)		(23)		(14)		(12)		(88)
Other noncurrent assets and liabilities		122		(34)		64		(4)		(31)

Total changes in other assets and liabilities	$	(24)	$	(57)	$	45	$	14	$	(161)

	Exelon		Generation			ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	186	$	186		$	0	$	0	$	0
Change in capital expenditures not paid		96		125	(e)		7		(35)		(7)

(b) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(c) In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 3 - Regulatory Matters for more information.

(d) Includes the establishment of a regulatory asset, pursuant to EIMA, for the 2011 annual reconciliation in ComEd's distribution formula rate tariff and the deferral of costs associated with significant 2011 storms, partially offset by an accrual to fund a new Science and Technology Innovation Trust. See Note 3 - Regulatory Matters for more information.

(e) Includes $120 million of capital expenditures not paid as of December 31, 2011 related to Antelope Valley.

For the Year Ended December 31, 2010	Exelon			Generation		ComEd			PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	665	^(a)	$	145	$	283		$	168	$	128
Income taxes (net of refunds)		1,219			732		15			433		(76)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	581		$	268	$	215		$	46	$	48
Provision for uncollectible accounts		108			1		48			59		38
Provision for obsolete inventory		12			12		0			0		0
Stock-based compensation costs		44			0		0			0		0
Other decommissioning-related activity^(b)		(91)			(91)		0			0		0
Energy-related options ^(c)		(73)			(73)		0			0		0
ARO adjustment		(19)			(8)		(10)			(1)		0
Amortization of regulatory asset related to debt costs		24			0		20			4		2
Amortization of rate stabilization deferral		0			0		0			0		62
Accrual for Illinois utility distribution tax refund (d)		(25)			0		(25)			0		0
Under-recovered uncollectible accounts, net (e)		(14)			0		(14)			0		0
ARP SO2 allowances impairment		57			57		0			0		0
Other		5			16		4			0		(6)

Total other non-cash operating activities	$	609		$	182	$	238		$	108	$	144

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	61		$	0	$	58		$	3	$	6
Other regulatory assets and liabilities		0			0		(19)			35		(64)
Other current assets		(18)			(16)		12			(19)		(7)
Other noncurrent assets and liabilities		(99)			(29)		(184)	^(f)		59		2

Total changes in other assets and liabilities	$	(56)		$	(45)	$	(133)		$	78	$	(63)

	Exelon		Generation		ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	(428)	$	(428)	$	0	$	0	$	0
Change in capital expenditures not paid		34		13		7		14		28
Purchase accounting adjustments		9		9		0		0		0
Exelon Wind acquisition (g)		32		32		0		0		0

(a) Excludes $167 million of interest paid to the IRS relating to a preliminary agreement reached during the third quarter of 2010. See Note 12 - Income Taxes for addition information.

(b) 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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(c) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(d) During the second quarter of 2010, ComEd recorded a reduction of $25 million to taxes other than income to reflect management's estimate of future refunds for the 2008 and 2009 tax years associated with Illinois' utility distribution tax based on an analysis of past refunds and interpretations of the Illinois Public Utility Act. Historically, ComEd has recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now has sufficient, reliable evidence to record and support an estimated receivable associated with the anticipated refund for the 2008 and 2009 tax years.

(e) Includes $70 million of under-recovered uncollectible accounts expense from 2008 and 2009 recorded in the first quarter of 2010 as well as $59 million of amortization of the associated regulatory asset. This amount also includes a credit of $3 million of under collections associated with 2010 activity. ComEd is recovering these costs through a rider mechanism authorized by the ICC. See Note 3 - Regulatory Matters for additional information regarding the Illinois legislation for recovery of uncollectible accounts.

(f) Relates primarily to a decrease in interest payable associated with a change in uncertain income tax positions. See Note 12 - Income Taxes for additional information.

(g) Represents contingent liability recorded in connection with the December 9, 2010 acquisition of Exelon Wind. See Note 4 - Acquisition for additional information.

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $103 million, $56 million and $47 million, respectively, and reimbursements of $113 million, $66 million and $47 million, respectively, related to PECO's and BGE's DOE SGIG programs. For the year ended December 31, 2011, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $51 million, $51 million and $23 million, respectively, and reimbursements of $56 million, $56 million and $41 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 3 - Regulatory Matters for additional information regarding the DOE SGIG.

Segment Information (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Segment Information [Abstract]

Segment Information (Exelon, Generation, ComEd and PECO)

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

Exelon has nine reportable segments, ComEd, PECO, BGE and Generation's six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation's expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income.

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 entire United States footprint of MISO, 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 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.

Exelon and Generation evaluate the performance of Generation's power marketing activities 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 affiliated sales to 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 our own generation and fuel costs associated with tolling agreements. Generation's other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency and demand response, the design, construction, and operation of renewable 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, are not allocated to regions. Further, Generation's compensation under the reliability-must-run rate schedule, results of operations from the Brandon Shores, Wagner, and C.P. Crane Maryland generating stations, and other miscellaneous revenues, 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 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 years ended December 31, 2012, 2011 and 2010 is as follows:

												Intersegment
		Generation (a)		ComEd		PECO		BGE(b)		Other(c)		Eliminations			Exelon
Operating revenues^(d):
	2012	$	14,437	$	5,443	$	3,186	$	2,091	$	1,396	$	(3,064)		$	23,489
	2011		10,447		6,056		3,720		-		830		(1,990)			19,063
	2010		10,025		6,204		5,519		-		755		(3,859)			18,644
Intersegment revenues^(e):
	2012	$	1,702	$	2	$	3	$	9	$	1,381	$	(3,042)		$	55
	2011		1,161		2		5		-		831		(1,990)			9
	2010		3,102		2		5		-		756		(3,859)			6
Depreciation and amortization
	2012	$	768	$	610	$	217	$	238	$	46	$	2		$	1,881
	2011		570		554		202		-		21		-			1,347
	2010		474		516		1,060		-		25		-			2,075
Operating expenses^(d):
	2012	$	13,226	$	4,557	$	2,563	$	2,053	$	1,662	$	(3,043)		$	21,018
	2011		7,571		5,074		3,065		-		863		(1,990)			14,583
	2010		6,979		5,148		4,858		-		792		(3,859)			13,918
Equity in earnings (losses) of unconsolidated affiliates
	2012	$	(91)	$	-	$	-	$	-	$	-	$	-		$	(91)
	2011		(1)		-		-		-		-		-			(1)
	2010		-		-		-		-		-		-			-
Interest expense, net:
	2012	$	301	$	307	$	123	$	111	$	86	$	-		$	928
	2011		170		345		134		-		77		-			726
	2010		153		386		193		-		85		-			817
Income (loss) before income taxes:
	2012	$	1,058	$	618	$	508	$	(54)	$	(276)	$	(56)		$	1,798
	2011		2,827		666		535		-		(59)		(13)			3,956
	2010		3,150		694		476		-		(91)		(8)			4,221
Income taxes:
	2012	$	500	$	239	$	127	$	(23)	$	(215)	$	(1)		$	627
	2011		1,056		250		146		-		9		(4)			1,457
	2010		1,178		357		152		-		(27)		(2)			1,658
Net income (loss):
	2012	$	558	$	379	$	381	$	(31)	$	(61)	$	(55)		$	1,171
	2011		1,771		416		389		-		(68)		(9)			2,499
	2010		1,972		337		324		-		(64)		(6)			2,563
Capital expenditures:
	2012	$	3,554	$	1,246	$	422	$	500	$	67	$	-		$	5,789
	2011		2,491		1,028		481		-		42		-			4,042
	2010		1,883		962		545		-		14		(78)	(f)		3,326
Total assets:
	2012	$	40,681	$	22,905	$	9,353	$	7,499	$	10,432	$	(12,316)		$	78,554
	2011		27,433		22,638		9,156		-		6,147		(10,379)			54,995

(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 year ended December 31, 2012 include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the years ended December 31, 2011 and 2010 intersegment revenues for Generation include revenue from sales to PECO of $508 million and $2,092 million, respectively, in the Mid-Atlantic region, and sales to ComEd of $653 million and $1,010 million, respectively, in the Midwest region.

(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2012.

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

(d) For the years ended December 31, 2012, 2011 and 2010, utility taxes of $82 million, $27 million and $0 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $239 million, $243 million and $205 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $141 million, $173 million and $271 million, respectively, are included in revenues and expenses for PECO. For the period of March 12, 2012 through December 31, 2012, utility taxes of $59 million are included in revenues and expenses for BGE.

(e) The intersegment profit associated with Generation's sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

(f) Represents capital projects transferred from BSC to Generation, ComEd and PECO. These projects are shown as capital expenditures at Generation, ComEd and PECO and the capital expenditure is eliminated upon consolidation.

Generation total revenues:
	2012						2011						2010
	Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	5,082	$	(44)	$	5,038	$	4,052	$	-	$	4,052	$	3,232	$	-	$	3,232
Midwest		4,824		24		4,848		5,445		-		5,445		5,762		-		5,762
New England		1,048		45		1,093		11		-		11		14		-		14
New York		582		(25)		557		0		-		0		0		-		0
ERCOT		1,365		2		1,367		575		-		575		543		-		543
Other Regions (b)		755		78		833		201		-		201		149		-		149
Total Revenues for Reportable Segments	$	13,656	$	80	$	13,736	$	10,284	$	-	$	10,284	$	9,700	$	-	$	9,700
Other (c)		781		(80)		701		163		-		163		325		-		325
Total Generation Consolidated Operating Revenues	$	14,437	$	0	$	14,437	$	10,447	$	-	$	10,447	$	10,025	$	-	$	10,025

(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 merger date.

Generation total revenues net of purchased power and fuel expense:
	2012						2011						2010
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	3,477	$	(44)	$	3,433	$	3,350	$	-	$	3,350	$	2,501	$	-	$	2,501
Midwest		2,974		24		2,998		3,547		-		3,547		4,081		-		4,081
New England		151		45		196		9		-		9		11		-		11
New York		101		(25)		76		0		-		0		0		-		0
ERCOT		403		2		405		84		-		84		(66)		-		(66)
Other Regions (b)		53		78		131		(14)		-		(14)		(65)		-		(65)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	7,159	$	80	$	7,239	$	6,976	$	-	$	6,976	$	6,462	$	-	$	6,462
Other (c)		217		(80)		137		(118)		-		(118)		100		-		100
Total Generation Revenues net of purchased power and fuel expense	$	7,376	$	0	$	7,376	$	6,858	$	-	$	6,858	$	6,562	$	-	$	6,562

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

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

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Related Party Transactions (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

22. Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:

		For the Period March 12,
		through December 31,
	2012
Equity investment income	$	83
Amortization of basis difference in CENG		(182)
Total equity in earnings (losses) - CENG	$	(99)

As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG.

In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Generation would record these distributions, if realized, in earnings in the period earned.

Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)

CENG

A subsidiary of Generation has an agreement under which it is purchasing 85-90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG's nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.

In addition to the PPA, a subsidiary of Generation has a power services agency agreement (PSAA) with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the service, with such cost not to exceed approximately $358,000 per month.

In addition to the PSAA, Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Under the SSA, BSC provides a variety of support services to CENG. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.

The impact of transactions under these agreements on Exelon's and Generation's Consolidated Financial Statements is summarized below:


	Income/(Expense)			Accounts
	For the Period		Income	Receivable/
	March 12 through		Statement	(Accounts Payable)
Agreement	December 31, 2012		Classification	At December 31, 2012
PPA	$	(793)	Purchased power and fuel	$	(83)
PSAA		3	Operating revenues		-
SSA		42	Operating revenues		5

In May 2011, CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount of $63 million from a subsidiary of Generation. CENG also issued a promissory note to EDF on substantially identical terms, such that any request for borrowings by CENG must be submitted 50.01% to Generation and 49.99% to EDF. The unsecured promissory note matured on October 31, 2012, and all amounts due were paid in full as of that date.

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:

		For the Years Ended
		December 31,
		2012		2011		2010
Operating revenues from affiliates:
	PECO (a)	$	6	$	9	$	6
	CENG (b)		42		0		0

	Total operating revenues from affiliates	$	48	$	9	$	6

Fuel and purchased power from related parties:
	CENG (c)	$	793	$	0	$	0
	Keystone Fuels, LLC		61		68		74
	Conemaugh Fuels, LLC		68		69		70

	Total fuel purchases from related parties	$	922	$	137	$	144

Charitable contribution to Exelon Foundation(d)		$	7	$	0	$	10

Interest expense to affiliates, net:
	ComEd Financing III	$	13	$	13	$	13
	PECO Trust III		6		6		6
	PECO Trust IV		6		6		6

	Total interest expense to affiliates, net	$	25	$	25	$	25

(Loss) gain in equity method investments:
	CENG equity investment income	$	73	$	0		0
	Amortization of basis difference in CENG (e)		(172)		0		0
	Other		8		(1)		0

	Total loss in equity method investments	$	(91)	$	(1)	$	0

		December 31,
		2012		2011
Investments in affiliates:
	ComEd Financing III	$	6	$	6
	PECO Energy Capital Corporation		4		4
	PECO Trust IV		4		5
	BGE Capital Trust II		8		0


	Total investments in affiliates	$	22	$	15

Receivables from affiliates (current):
	CENG (b)	$	16	$	0

Payables to affiliates (current):
	CENG (c)	$	83	$	0
	ComEd Financing III		4		4
	PECO Trust III		1		1

	Total payables to affiliates (current)	$	88	$	5

Long-term debt to BondCo and other financing trusts (including due within one year):
	ComEd Financing III	$	206	$	206
	PECO Trust III		81		81
	PECO Trust IV		103		103
	BGE Capital Trust II		258		0

	Total long-term debt due to financing trusts	$	648	$	390

Transactions involving Generation, ComEd, PECO and BGE are further described in the tables below.

Generation

The financial statements of Generation include related party transactions as presented in the tables below:

		For the Years Ended
		December 31,
		2012		2011		2010
Operating revenues from affiliates:
	ComEd (a)	$	795	$	653	$	1,010
	PECO (b)		543		508		2,092
	BGE (c)		322		0		0
	CENG (d)		42		0		0

	Total operating revenues from affiliates	$	1,702	$	1,161	$	3,102

Fuel and purchased power from related parties:
	PECO	$	0	$	1	$	1
	BGE		8		0		0
	CENG (e)		793		0		0
	Keystone Fuels, LLC		61		68		74
	Conemaugh Fuels, LLC		68		69		70

	Total fuel purchases from related parties	$	930	$	138	$	145

Operating and maintenance from affiliates:
	ComEd (f)	$	2	$	2	$	2
	PECO (f)		3		5		4
	BSC (g)		625		314		285

	Total operating and maintenance from affiliates	$	630	$	321	$	291

(Loss) gain in equity method investments
	CENG equity investment income		73		0		0
	Amortization of basis difference in CENG (h)		(172)		0		0
	Qualifying facilities and domestic power projects		8		(1)		0

	Total loss in equity method investments		(91)	$	(1)	$	0

Cash distribution paid to member		$	1,626	$	172	$	1,508

Contribution from member		$	48	$	30	$	62

		December 31,
		2012		2011
Mark-to-market derivative assets with affiliates (current):
	ComEd (i)	$	226	$	503

Receivables from affiliates (current):
	ComEd (a)(j)	$	54	$	70
	PECO (b)		56		39
	BGE (c)		31		0

	Total receivables from affiliates (current)	$	141	$	109

Receivable from affiliate (noncurrent)
	Exelon	$	1	$	1

Mark-to-market derivative assets with affiliates (noncurrent):
	ComEd (i)	$	0	$	191

Payables to affiliates (current):
	CENG (e)	$	83	$	0
	Exelon (k)		33		7
	BSC (g)		77		51

	Total payables to affiliates (current)	$	193	$	58

Payables to affiliates (noncurrent):
	ComEd (l)	$	2,037	$	1,857
	PECO (l)		360		365

	Total payables to affiliates (noncurrent)	$	2,397	$	2,222

(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information.

(b) Generation had a PPA with PECO to provide the full energy requirements to PECO through 2010. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information.

(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information.

(d) Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Under the SSA, BSC provides a variety of support services to CENG. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.

(e) A subsidiary of Generation has an agreement under which it is purchasing 85-90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG's nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.

(f) Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.

(g) Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(h) As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG. In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Through purchase accounting, Generation recorded the fair value of expected future distributions. Generation will record these distributions when realized as a reduction in its investment in CENG. Distributions realized in excess of the fair value recorded would be recorded in earnings in the period earned.

(i) Represents the fair value of Generation's five-year financial swap contract with ComEd.

(j) Generation had a $53 million and $53 million receivable from ComEd at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Instruments for additional information.

(k) In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(l) Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 13 - Asset Retirement Obligations.

ComEd

The financial statements of ComEd include related party transactions as presented in the tables below:

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates
	Generation	$	2	$	2	$	2

Purchased power from affiliate
	Generation (a)	$	789	$	653	$	1,010

Operating and maintenance from affiliate
	BSC (b)	$	163	$	158	$	152

Interest expense to affiliates, net:
	Exelon	$	0	$	2	$	0
	ComEd Financing III		13		13		13

	Total interest expense to affiliates, net	$	13	$	15	$	13

Capitalized costs
	BSC (b)	$	92	$	85	$	84

Cash dividends paid to parent		$	105	$	300	$	310

Contribution from parent		$	11	$	11	$	2

		December 31,
		2012			2011
Prepaid voluntary employee beneficiary association trust (c)		$	10	$	12

Investment in affiliate
	ComEd Financing III	$	6	$	6

Receivable from affiliates (noncurrent):
	Generation (d)	$	2,037	$	1,857
	Other		2		3

	Total receivable from affiliates (noncurrent)	$	2,039	$	1,860

Payables to affiliates (current):
	Generation (a)(e)	$	54	$	70
	BSC (b)		35		35
	ComEd Financing III		4		4
	Other		4		2

	Total payables to affiliates (current)	$	97	$	111

Mark-to-market derivative liability with affiliate (current)
	Generation (f)	$	226	$	503

Mark-to-market derivative liability with affiliate (noncurrent)
	Generation (f)	$	0	$	191

Long-term debt to ComEd financing trust
	ComEd Financing III	$	206	$	206

____________________

(a) ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Instruments for additional information.

(b) ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c) The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd's contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

(d) ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd's customers.

(e) ComEd had a $53 million and $53 million payable to Generation at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Information for additional information.

(f) To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation.

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates:
	Generation (a)	$	3	$	5	$	5

Purchased power from affiliate
	Generation (b)	$	533	$	495	$	2,085

Operating and maintenance from affiliates:
	BSC (c)	$	107	$	92	$	89
	Generation		4		4		0

	Total operating and maintenance from affiliates	$	111	$	96	$	89

Interest expense to affiliates, net:
	PECO Trust III	$	6	$	6	$	6
	PECO Trust IV		6		6		6

	Total interest expense to affiliates, net	$	12	$	12	$	12

Loss in equity method investments

Capitalized costs
	BSC (c)	$	54	$	60	$	40

Cash dividends paid to parent		$	343	$	348	$	224

Repayment of receivable from parent		$	0	$	0	$	180

Contribution from parent		$	9	$	18	$	43

		December 31,
		2012		2011
Prepaid voluntary employee beneficiary association trust (d)		$	2	$	3

Investments in affiliates:
	PECO Energy Capital Corporation	$	4	$	4
	PECO Trust IV		4		4

	Total investments in affiliates	$	8	$	8

Receivable from affiliate (noncurrent):
	Generation (e)	$	360	$	365

Mark-to-market derivative liability with affiliate (current):

Payables to affiliates (current):
	Generation (b)	$	56	$	39
	BSC (c)		18		21
	Exelon		1		1
	PECO Trust III		1		1

	Total payables to affiliates (current)	$	76	$	62

Long-term debt to financing trusts (including amounts due within one year):
	PECO Trust III	$	81	$	81
	PECO Trust IV		103		103

	Total long-term debt to financing trusts	$	184	$	184

________

(a) PECO provides energy to Generation for Generation's own use.

(b) PECO obtained all of its electric supply from Generation through 2010 under a PPA. Beginning January 1, 2011, PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs.

(c) PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d) The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(e) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers.

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates:
	Generation (a)	$	10	$	8	$	7

Purchased power from affiliate
	Generation (b)	$	396	$	348	$	428

Operating and maintenance from affiliates:
	BSC (c)	$	106	$	150	$	126

Capitalized costs
	BSC (c)	$	21	$	29	$	49

Cash dividends paid to parent		$	0	$	(85)	$	0

Contribution from parent		$	66	$	0	$	0

		December 31,
		2012		2011

Investments in affiliates:
	BGE Capital Trust II	$	8	$	8

Payables to affiliates (current):
	Generation (b)	$	31	$	41
	BSC (c)		12		-
	Exelon (d)		17		-
	ComEd		3		-
	PECO		2		-

	Total payables to affiliates (current)	$	65	$	41

Long-term debt to BGE financing trust
	BGE Capital Trust II	$	258	$	258

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39603-107864

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39622-107864

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39549-107864

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39678-107864

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(k))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39691-107864

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph b
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph k
-Article 4

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Quarterly Data (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information [Abstract]

Quarterly Financial Information Text Block

23. Quarterly Data (Unaudited) (Exelon, Generation, ComEd and PECO)

Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:

									Net Income
									on Common
	Operating Revenues				Operating Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	4,686	$	4,956	$	359	$	1,202	$	200	$	668
June 30		5,954		4,496		714		1,034		286		620
September 30		6,565		5,254		603		1,181		296		601
December 31		6,284		4,357		704		1,062		378		606

	Average Basic Shares
	Outstanding				Net Income
	(in millions)				per Basic Share
	2012		2011		2012		2011
Quarter ended:
March 31		705		662	$	0.28	$	1.01
June 30		853		663		0.34		0.93
September 30		854		663		0.35		0.91
December 31		854		664		0.44		0.91

	Average Diluted Shares
	Outstanding				Net Income
	(in millions)				per Diluted Share
	2012		2011		2012		2011
Quarter ended:
March 31		707		664	$	0.28	$	1.01
June 30		856		664		0.33		0.93
September 30		857		665		0.35		0.90
December 31		857		666		0.44		0.91

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:

	2012								2011

	Fourth		Third		Second		First		Fourth			Third		Second		First
	Quarter		Quarter		Quarter		Quarter		Quarter			Quarter		Quarter		Quarter

High price	$	37.50	$	39.82	$	39.37	$	43.70	$	45.45		$	45.27	$	42.89	$	43.58
Low price		28.40		34.54		36.27		38.31		39.93			39.51		39.53		39.06
Close		29.74		35.58		37.62		39.21		43.37			42.61		42.84		41.24
Dividends		0.525		0.525		0.525		0.525		0.525	(a)		0.525		0.525		0.525

_____________________

(a) The fourth quarter 2011 dividend does not include the first quarter 2012 regular quarterly dividend of $0.525 per share, declared by the Exelon Board of Directors on October 25, 2011. The first quarter 2012 dividend is payable on March 9, 2012, to shareholders of record of Exelon at the end of the day on February 15, 2012.

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:

									Net Income
									on Membership
	Operating Revenues				Operating Income				Interest
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	2,739	$	2,643	$	272	$	801	$	168	$	495
June 30		3,753		2,455		384		647		166		443
September 30		4,017		2,821		174		754		91		386
December 31		3,928		2,528		290		673		137		447

ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:

	Operating Revenues				Operating Income				Net Income
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	1,388	$	1,466	$	226	$	200	$	87	$	69
June 30		1,281		1,444		142		254		42		114
September 30		1,484		1,784		218		243		90		112
December 31		1,290		1,362		300		285		160		121

PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:

									Net Income
									on Common
	Operating Revenues				Operating Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	875	$	1,153	$	177	$	210	$	96	$	125
June 30		715		842		151		161		79		82
September 30		806		946		178		153		122		104
December 31		790		778		117		131		79		73

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:

									Net (Loss) Income
					Operating				on Common
	Operating Revenues				(Loss) Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	696	$	976	$	(11)	$	153	$	(33)	$	78
June 30		616		674		52		54		13		13
September 30		720		745		30		23		(4)		(2)
December 31		703		673		61		84		15		34

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2012
Accounting Policies [Abstract]
Nature of Operations [Text Block]	Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for a retail power supply VIE for which Generation has no ownership interest but does have a controlling financial interest through contractual arrangements; Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon's consolidated financial statements; and certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in noncontrolling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the Noncontrolling members for certain of these projects. ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2012, as equity.
Consolidation, Policy [Text Block]	Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd and PECO. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions. For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded these correcting adjustments are not material to its results of operations or cash flows for the year ended December 31, 2012, or any prior period. The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
Use Of Estimates	Use of Estimates (Exelon, Generation, ComEd, PECO and BGE) The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.
Reclassifications	Reclassifications (Exelon, Generation, ComEd, PECO and BGE) Certain prior year amounts in Exelon's, Generation's and BGE's Consolidated Statements of Cash Flows, Exelon's, Generation's, PECO's, ComEd's and BGE's Consolidated Statements of Operations and Comprehensive Income and in Exelon's, Generation's, ComEd's, PECO's and BGE'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.
Consolidation Variable Interest Entity Policy [Text Block]	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. These items represent amounts on Generation's and Exelon's balance sheet related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $614 million and $734 million as of December 31, 2012 and December 31, 2011, respectively; offset by payables to ZionSolutions LLC of $564 million and $691 million as of December 31, 2012 and December 31, 2011, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 – Asset Retirement Obligations for further discussion. Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these variable interest entities. Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sells power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation is not required. ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 13 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 19 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. ComEd, PECO and BGE ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 19 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs generally represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2012, the total amount of accounts payable owed by the utilities under agreements with VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in any VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. PECO PETT, a financing trust, was created in 1998 by PECO to purchase and own intangible transition property (ITP) and to issue transition bonds to securitize $5 billion of PECO's stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PETT was consolidated in Exelon's and PECO's financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective on that date. Under the guidance, PECO concluded that it was the primary beneficiary of PETT due to PECO's involvement in the design of PETT, its role as servicer, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT's other expenses. The consolidation of PETT did not have a significant impact on PECO's results of operations or statement of cash flows. Upon retirement of the outstanding transition bonds on September 1, 2010, the remaining cash balance was remitted to PECO, and PETT was dissolved on September 20, 2010.
Public Utilities Policy [Text Block]	Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulations, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities' costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd's, PECO's or BGE's business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information. Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations. Amortization of regulatory assets is recorded over the recovery period specified in the related legislation or regulatory agreement and is included in depreciation and amortization expense on ComEd's, PECO's and BGE's Consolidated Statements of Operations and Comprehensive Income. See Note 3—Regulatory Matters and 20—Supplemental Financial Information for additional information regarding Generation's nuclear fuel, Generation's ARC and the amortization of ComEd's, PECO's and BGE's regulatory assets.
Inventory Policy [Text Block]	Revenues (Exelon, Generation, ComEd, PECO and BGE) Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Notes 3—Regulatory Matters and 5—Accounts Receivable for further information. RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Company in the different RTOs and ISOs. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. Premiums received and paid on option contracts are recognized as revenue or expense over the terms of the contracts. Since ComEd is entitled to full recovery of the costs of the financial swap contract with Generation in rates as settlements occur, ComEd records the fair value of the swap as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. See Note 3—Regulatory Matters for further information. Proprietary Trading Activities. Exelon and Generation account for Generation's trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note – 10 Derivative Financial Instruments for further discussion. Income Taxes (Exelon, Generation, ComEd, PECO and BGE) Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants' Consolidated Balance Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, the Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or in other income and deductions (interest income) on their Consolidated Statements of Operations. Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 12—Income Taxes for further information. Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE) Exelon, Generation, ComEd, PECO and BGE present any tax assessed by a governmental authority that is the liability of the Registrants and is directly imposed on a revenue-producing transaction between a seller and a customer on a gross (included in revenues and costs) basis. See Note 20—Supplemental Financial Information for Generation's, ComEd's, PECO's and BGE's utility taxes that are presented on a gross basis. Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE) The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Investments (Exelon, Generation, ComEd, PECO and BGE) Restricted cash and investments represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2012 and 2011, Exelon Corporate's restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, Exelon Corporate has funds restricted for merger commitments. In addition, Exelon Corporate's investments include its direct financing lease investments. As of December 31, 2012, Generation's restricted cash and investments primarily included cash at one of its consolidated variable interest entities and, as of 2011, primarily represented funds in escrow related to the acquisition of Shooting Star Wind Project, LLC and cash for payment of certain environmental liabilities. As of December 31, 2012 and 2011, ComEd's restricted cash primarily represented cash collateral held from suppliers associated with ComEd's energy and REC procurement contracts. As of December 31, 2011, PECO's restricted cash primarily represented funds from the sales of assets that were subject to PECO's mortgage indenture. As of December 31, 2012 and 2011, BGE's restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds. Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2012 and 2011, Exelon's and Generation's NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2012, Exelon, ComEd, PECO and BGE had short-term investments in Rabbi trusts classified as noncurrent assets. Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE) The allowance for uncollectible accounts reflects the Registrants' best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable agings, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. BGE estimates the allowance for uncollectible accounts on customer receivables by assigning reserve factors for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. ComEd, PECO and BGE customers' accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd's, PECO's and BGE's provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3 —Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes the following specific requirements: requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE, requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, amends the events that trigger a reassessment of whether an entity is a VIE, and requires the entity that consolidates a VIE (the primary beneficiary) to present separately on the face of its balance sheet (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities: Exelon has presented separately on its Consolidated Balance Sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon's consolidated VIEs for which creditors do not have recourse to Exelon's general credit. Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. Exelon has evaluated all existing entities under the new VIE accounting requirements, both those previously considered VIEs and those considered potential VIEs. Exelon's accounting for and disclosure about VIEs did not change materially as a result of these assessments. See Note 2 – Variable Interest Entities for additional information. Inventories (Exelon, Generation, ComEd, PECO and BGE) Inventory is recorded at the lower of weighted average cost or market. Provisions are recorded for excess and obsolete inventory. Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, propane and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used or sold. Materials and Supplies. Materials and supplies inventory generally includes the weighted average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, when installed or used. Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations.
Property Plant And Equipment Policy [Text Block]	Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) Property, plant and equipment is recorded at original cost. Original cost includes labor, materials and construction overhead. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred. For constructed assets, Exelon capitalizes construction-related direct labor and material costs. ComEd, PECO and BGE also capitalized indirect construction costs including labor and related costs of departments associated with supporting construction activities. Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE are accounted for as CIAC. For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to operating and maintenance expense as incurred. For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd's and BGE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. ComEd's and BGE's actual incurred removal costs are applied against a related regulatory liability. PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. Generation's oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred. See Note 6—Property, Plant and Equipment, Note 7—Jointly Owned Electric Utility Plant and Note 20—Supplemental Financial Information for additional information regarding property, plant and equipment. __________ (a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010. Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE) Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd's and BGE's depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation's operating nuclear generating stations except for Oyster Creek. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations. See Note 6—Property, Plant and Equipment for further information regarding depreciation.
Asset Retirement Obligations And Environmental Cost Policy [Text Block]	Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years. The liabilities associated with Exelon's non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd's and PECO's accretion, through an increase to regulatory assets. See Note 13—Asset Retirement Obligations for additional information.
Impairment Or Disposal Of Long Lived Assets Policy [Text Block]	Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Cash flows from Generation plant assets are evaluated at a regional portfolio level along with cash flows generated from Generation's supply and risk management activities, including cash flows from contracts that are recorded as intangible contract assets and liabilities on the balance sheet. For ComEd, PECO, and BGE, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity provided. For ComEd, the lowest level of independent cash flows is transmission and distribution and, for PECO and BGE, the lowest level of independent cash flows is transmission, distribution and gas. An impairment loss is recorded if the undiscounted expected future cash flows are less than the carrying amount of the long-lived asset or asset group. The amount of the impairment loss recorded is the difference between the estimated fair value of the long-lived asset or asset group and the carrying value. Conditions that could have an adverse impact on the expected future cash flows and the fair value of the long-lived assets and asset groups include, among other factors, a deteriorating business climate, including current energy and market conditions, revisions to regulatory laws, or plans to dispose of a long-lived asset significantly before the end of its useful life.
Goodwill And Intangible Assets Policy [Text Block]	Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 8—Intangible Assets for additional information regarding Exelon's and ComEd's goodwill.
Derivatives Policy [Text Block]	Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that do not qualify or are not designated for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel or other, net on the Consolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon's Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. For derivative commodity contracts, effective with the date of the merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be 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 derivatives executed to hedge economic risk for commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the applicable requirements, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings at Generation or offset by a regulatory asset or liability at ComEd, PECO and BGE. See Note 10—Derivative Financial Instruments for additional information.
Compensation Related Costs Policy [Text Block]	Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation's defined benefit pension and other postretirement benefit plans and defined contribution savings plans. The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14—Retirement Benefits for additional discussion of Exelon's accounting for retirement benefits.
Marketable Securities Policy [Text Block]	Marketable Securities (Exelon, Generation, ComEd, PECO and BGE) All marketable securities are reported at fair value. Marketable securities held in the NDT funds and BGE's Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former AmerGen nuclear generating units, the Zion generating station and portions of the Peach Bottom nuclear generating units not subject to a regulatory agreement (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on BGE's Rabbi trust investments are included in earnings at Exelon and BGE. Unrealized gains and losses, net of tax, for ComEd's and PECO's available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd's and PECO's available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 13— Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 20—Supplemental Financial Information for additional information regarding ComEd's and PECO's regulatory assets and liabilities.
Allowance For Funds Used During Construction Policy [Text Block]	Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
Research Development And Computer Software Disclosure [Text Block]	Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE) Costs incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:
Property Plant And Equipment Interest Capitalization [Text Block]	During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
Guarantees Indemnifications And Warranties Policies [Text Block]	Guarantees (Exelon, Generation, ComEd, PECO and BGE) The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 19—Commitments and Contingencies for additional information.
Nuclear Fuel Policy [Text Block]	Nuclear Fuel (Exelon and Generation) The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. The estimated disposal cost of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed to operating and maintenance expense as incurred based upon the nature of the costs. A portion of the storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed.
Nuclear Outage Costs Policy [Text Block]	Nuclear Outage Costs (Exelon and Generation) Costs associated with nuclear outages, including planned major maintenance activities, are expensed to operating and maintenance expense or capitalized to property, plant and equipment (based on the nature of the activities) in the period incurred.
New site development costs nuclear outage costs policy [Text Block]	New Site Development Costs (Exelon and Generation) New site development costs represent the costs incurred in the assessment, design and construction of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management's determination that the project is economically and operationally feasible, management and/or the Exelon Board of Directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Upon commencement of construction, these costs will be charged to construction work in progress. Capitalized development costs are charged to operating and maintenance expense when project completion is no longer probable. At December 31, 2012 and 2011, Exelon's and Generation's capitalized development costs totaled approximately $1.2 billion and $376 million, respectively, which are included in Property, Plant and Equipment on Exelon's and Generation's Consolidated Balance Sheets. Costs included in the balance as of December 31, 2012 primarily relate to the development of the Antelope Valley project along with other, smaller renewable energy projects. See Note 4 - Merger and Acquisitions for additional information on Antelope Valley. Costs included in the balance as of December 31, 2011 primarily relate to land rights and other third-party costs directly associated with the development of certain Exelon Wind projects. Approximately $4 million, $2 million and $6 million of costs were expensed by Exelon and Generation for the years ended December 31, 2012, 2011 and 2010, respectively. These costs primarily related to the possible development of new renewable energy projects.

Basis of Presentation (Policies)	12 Months Ended
Basis of Presentation (Policies)	Dec. 31, 2012
Basis of Presentation (Policies) [Abstract]
Nature of Operations [Text Block]	Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for a retail power supply VIE for which Generation has no ownership interest but does have a controlling financial interest through contractual arrangements; Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon's consolidated financial statements; and certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in noncontrolling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the Noncontrolling members for certain of these projects. ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2012, as equity.
Consolidation, Policy [Text Block]	Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd and PECO. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions. For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded these correcting adjustments are not material to its results of operations or cash flows for the year ended December 31, 2012, or any prior period. The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
Consolidation Variable Interest Entity Policy [Text Block]	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. These items represent amounts on Generation's and Exelon's balance sheet related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $614 million and $734 million as of December 31, 2012 and December 31, 2011, respectively; offset by payables to ZionSolutions LLC of $564 million and $691 million as of December 31, 2012 and December 31, 2011, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 – Asset Retirement Obligations for further discussion. Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these variable interest entities. Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sells power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation is not required. ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 13 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 19 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. ComEd, PECO and BGE ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 19 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs generally represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2012, the total amount of accounts payable owed by the utilities under agreements with VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in any VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. PECO PETT, a financing trust, was created in 1998 by PECO to purchase and own intangible transition property (ITP) and to issue transition bonds to securitize $5 billion of PECO's stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PETT was consolidated in Exelon's and PECO's financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective on that date. Under the guidance, PECO concluded that it was the primary beneficiary of PETT due to PECO's involvement in the design of PETT, its role as servicer, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT's other expenses. The consolidation of PETT did not have a significant impact on PECO's results of operations or statement of cash flows. Upon retirement of the outstanding transition bonds on September 1, 2010, the remaining cash balance was remitted to PECO, and PETT was dissolved on September 20, 2010.

- Definition

Disclosure of accounting policy regarding (1) the principles it follows in consolidating or combining the separate financial statements, including the principles followed in determining the inclusion or exclusion of subsidiaries or other entities in the consolidated or combined financial statements and (2) its treatment of interests (for example, common stock, a partnership interest or other means of exerting influence) in other entities, for example consolidation or use of the equity or cost methods of accounting. The accounting policy may also address the accounting treatment for intercompany accounts and transactions, noncontrolling interest, and the income statement treatment in consolidation for issuances of stock by a subsidiary.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-URI http://asc.fasb.org/subtopic&trid=2197480

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 860
-SubTopic 40
-Section 45
-URI http://asc.fasb.org/section&trid=2197723

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-URI http://asc.fasb.org/subtopic&trid=2196966

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 325
-SubTopic 20
-URI http://asc.fasb.org/subtopic&trid=2197087

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.3A-02)
-URI http://asc.fasb.org/extlink&oid=6959686&loc=d3e355033-122828

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 45
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=16385135&loc=d3e33801-111570

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=18733093&loc=d3e5614-111684

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 5, 6, 16-19
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 96-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph a(2)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 2-6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 97-2
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph k
-Article 1

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 140
-Paragraph 46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02, 03
-Article 3A

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies Tables [Abstract]

Schedule Of Capitalized Software [Text Block]

Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	499	$	143	$	105	$	63	$	157
December 31, 2011		280		82		120		67		62

Amortization of capitalized software costs	Exelon ^(a)		Generation^(a)		ComEd		PECO		BGE ^(a)

2012	$	208	$	81	$	56	$	30	$	32
2011		122		41		50		25		25
2010		104		33		41		19		26

Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010

Schedule Of Capitalized Interest And AFUDC [Text Block]

		Exelon^(a)		Generation ^(a)		ComEd		PECO		BGE^(a)

2012	Total incurred interest^(b)	$	1,003	$	368	$	310	$	125	$	149
	Capitalized interest		67		67		—		—		—
	Credits to AFUDC debt and equity		25		—		9		6		15

2011	Total incurred interest^(b)	$	783	$	219	$	349	$	138	$	136
	Capitalized interest		49		49		—		—		—
	Credits to AFUDC debt and equity		25		—		12		13		22

2010	Total incurred interest^(b)	$	861	$	191	$	388	$	197	$	137
	Capitalized interest		38		38		—		—		—
	Credits to AFUDC debt and equity		16		—		5		11		16

__________

(b) Includes interest expense to affiliates.

Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2012

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities [Table Text Block]

		December 31, 2012						December 31, 2011
		Exelon (a)		Generation		BGE (b)		Exelon		Generation		BGE (b)
Current assets		$	550	$	519	$	30	$	15	$	15	$	30
Noncurrent assets			1,802		1,762		-		784		784		-
	Total assets	$	2,352	$	2,281	$	30	$	799	$	799	$	30

Current liabilities		$	685	$	613	$	71	$	181	$	181	$	69
Noncurrent liabilities			837		532		265		77		77		332
	Total liabilities	$	1,522	$	1,145	$	336	$	258	$	258	$	401

Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=7880789&loc=d3e5747-111685

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=7880789&loc=SL6228884-111685

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7880789&loc=d3e5728-111685

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Variable Interest Entity
-URI http://asc.fasb.org/extlink&oid=6528138

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7880789&loc=d3e5710-111685

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=7880789&loc=SL6759159-111685

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 140
-Paragraph 35
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 2, 14, 15, 16, 23, 24, 25, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 24
-Appendix D

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS140-4/FIN46(R)-8
-Paragraph C4
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 22B
-Appendix D

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 23A
-Appendix D

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Paragraph 22E
-Appendix D

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph g
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Variable Interest Entities [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

		December 31, 2012						December 31, 2011
		Exelon (a)		Generation		BGE (b)		Exelon		Generation		BGE (b)
Current assets		$	550	$	519	$	30	$	15	$	15	$	30
Noncurrent assets			1,802		1,762		-		784		784		-
	Total assets	$	2,352	$	2,281	$	30	$	799	$	799	$	30

Current liabilities		$	685	$	613	$	71	$	181	$	181	$	69
Noncurrent liabilities			837		532		265		77		77		332
	Total liabilities	$	1,522	$	1,145	$	336	$	258	$	258	$	401

Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

Schedule Of Unconsolidated Variable Interest Entities [Text Block]

				Equity
		Commercial		Method
		Agreement		Investment
December 31, 2012		VIEs		VIEs		Total
Total assets (a)		$	386	$	354	$	740
Total liabilities (a)			219		114		333
Registrants' ownership interest (a)			0		97		97
Other ownership interests (a)			167		143		310
Registrants' maximum exposure to loss:
	Letters of credit		5		0		5
	Carrying amount of equity method investments		0		77		77
	Contract intangible asset		8		0		8
	Debt and payment guarantees		0		5		5
	Net assets pledged for Zion Station decommissioning (b)		50		0		50

				Equity
		Commercial		Method
		Agreement		Investment
December 31, 2011		VIEs		VIEs		Total
Registrants' maximum exposure to loss:
	Net assets pledged for Zion Station decommissioning (b)		43		0		43

- Definition

+ References

+ Details

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Regulatory Matters Tables [Abstract]

Illinois Settlement Agreement contributions

		Generation		ComEd		Total Credits Issued to ComEd Customers
Year Ended December 31, 2010		Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers(a)	$	14	$	1	$	15
Credits to other Illinois utilities’ customers(a)		7		n/a		n/a
Total incurred costs	$	21	$	1	$	15

(a) Recorded as a reduction in operating revenues.

Regulatory assets and liabilities

December 31, 2012		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits	$	304	$	3,673	$	0	$	0	$	0	$	0	$	0	$	0
Deferred income taxes			14		1,382		5		62		0		1,255		9		65
AMI programs			3		70		3		10		0		29		0		31
AMI meter events			0		17		0		0		0		17		0		0
Under-recovered distribution service
	costs		18		191		18		191		0		0		0		0
Debt costs			14		68		11		62		3		6		1		9
Fair value of BGE long-term debt (a)			0		256		0		0		0		0		0		0
Fair value of BGE supply contract (b)			77		12		0		0		0		0		0		0
Severance			29		28		25		12		0		0		4		16
Asset retirement obligations			0		90		0		65		0		25		0		0
MGP remediation costs			58		232		51		197		6		33		1		2
RTO start-up costs			3		2		3		2		0		0		0		0
Under-recovered electric universal
	service fund costs		11		0		0		0		11		0		0		0
Financial swap with Generation			0		0		226		0		0		0		0		0
Renewable energy and associated
	RECs		18		49		18		49		0		0		0		0
Under-recovered energy and
	transmission costs		43		0		14		0		1		0		28		0
DSP Program costs			1		3		0		0		1		3		0		0
DSP II Program costs			1		2		0		0		1		2		0		0
Deferred storm costs			3		6		0		0		0		0		3		6
Electric generation-related
	regulatory asset		16		40		0		0		0		0		16		40
Rate stabilization deferral			67		225		0		0		0		0		67		225
Energy efficiency and demand
	response programs		56		126		0		0		0		0		56		126
Other			23		25		14		16		9		8		0		2

Total regulatory assets		$	759		6,497	$	388	$	666	$	32	$	1,378	$	185	$	522

_________________

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. See Note 4 – Merger and Acquisitions for additional information.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved regulated rates. See Note 4 – Merger and Acquisitions for additional information.

December 31, 2012		Exelon				ComEd				PECO				BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,397	$	0	$	2,037	$	0	$	360	$	0	$	0
Removal costs			97		1,406		75		1,192		0		0		22		214
Energy efficiency and demand
	response programs		131		0		43		0		88		0		0		0
Electric distribution tax repairs			20		132		0		0		20		132		0		0
Gas distribution tax repairs			8		46						8		46
Over-recovered uncollectible
	accounts		6		0		6		0		0		0		0		0
Over-recovered energy and
	transmission costs		54		0		6		0		48		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3		0		0		0
Over-recovered AEPS costs			2		0		0		0		2		0		0		0

Total regulatory liabilities		$	321	$	3,981	$	130	$	3,229	$	169	$	538	$	22	$	214

December 31, 2011		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits	$	204	$	2,794	$	0	$	0	$	7	$	0	$	3	$	0
Deferred income taxes			5		1,176		5		66		0		1,110		8		68
AMI and smart meter programs			2		28		2		6		0		22		0		15
Under-recovered distribution service
	costs		14		70		14		70		0		0		0		0
Debt costs			18		81		15		73		3		8		2		10
Severance			25		38		25		38		0		0		0		1
Asset retirement obligations			0		74		0		50		0		24		0		0
MGP remediation costs			30		129		24		91		6		38		1		2
RTO start-up costs			3		4		3		4		0		0		0		0
Under-recovered electric universal
	service fund costs		3		0		0		0		3		0		0		0
Financial swap with Generation			0		0		503		191		0		0		0		0
Renewable energy and associated
	RECs		9		97		9		97		0		0		0		0
Under-recovered energy and
	transmission costs		57		0		48		0		9		0		50		0
DSP Program costs			3		2		0		0		3		2		0		0
Deferred storm costs			0		0		0		0		0		0		3		9
Electric generation-related
	regulatory asset		0		0		0		0		0		0		16		56
Rate stabilization deferral			0		0		0		0		0		0		63		295
Energy efficiency and demand
	response programs		0		0		0		0		0		0		29		95
Other			17		25		9		13		8		12		0		0

Total regulatory assets		$	390	$	4,518	$	657	$	699	$	39	$	1,216	$	175	$	551

December 31, 2011		Exelon				ComEd				PECO				BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,222	$	0	$	1,857	$	0	$	365	$	0	$	0
Removal costs			61		1,185		61		1,185		0		0		18		200
Energy efficiency and demand
	response programs		49		69		49		0		0		69		0		0
Electric distribution tax repairs			19		151		0		0		19		151		0		0
Over-recovered uncollectible
	accounts		15		0		15		0		0		0		0		0
Over-recovered energy and
	transmission costs		42		0		12		0		30		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3		0		0		0
Over-recovered AEPS costs			8		0		0		0		8		0		0		0
Other			0		0		0		0		0		0		1		1

Total regulatory liabilities		$	197	$	3,627	$	137	$	3,042	$	60	$	585	$	19	$	201

Regulatory Construction Commitment

		Total		2013		2014		2015		2016		2017

ComEd	$	525	$	175	$	86	$	135	$	128	$	1
PECO		140		28		23		26		36		27
BGE		249		15		53		119		55		7

Purchase Of Receivables [Table Text Block]

As of December 31, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	191	$	55	$	65	$	71
Allowance for uncollectible accounts (b)		(21)		(9)		(6)		(6)
Purchased receivables, net	$	170	$	46	$	59	$	65

As of December 31, 2011	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	68	$	16	$	52	$	61
Allowance for uncollectible accounts (b)		(5)		-		(5)		(3)
Purchased receivables, net	$	63	$	16	$	47	$	58

Merger and Acquisitions (Tables)

12 Months Ended

Dec. 31, 2012

Business Acquisition [Line Items]

Schedule of Business Acquisitions by Acquisition, Contingent Consideration [Table Text Block]

Description		Payment Period	BGE		Generation		Exelon		Statement of Operations Location
BGE rate credit of $100 per residential customer (a)		Q2 2012	$	113	$	0	$	113	Revenues
Customer investment fund to invest in energy efficiency
	and low-income energy assistance to BGE customers	2012 to 2014		0		0		113.5	O&M Expense
Contribution for renewable energy, energy efficiency
	or related projects in Baltimore	2012 to 2014		0		0		2	O&M Expense
Charitable contributions at $7 million per year for 10 years		2012 to 2021		28		35		70	O&M Expense
State funding for offshore wind development projects		Q2 2012		0		0		32	O&M Expense
Miscellaneous tax benefits		Q2 2012		(2)		0		(2)	Taxes Other Than Income
	Total		$	139	$	35	$	328.5

Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.

Schedule of Business Acquisitions by Acquisition, Equity Interest Issued or Issuable [Table Text Block]

	Number of Shares/ Awards Issued	Total Fair Value
Issuance of Exelon common stock to Constellation shareholders and equity award holders at the exchange ratio of 0.930 shares for each share of Constellation common stock; based on the opening price of Exelon common stock on March 12, 2012 of $38.91 (a)	187.45	$	7,294
Issuance of Exelon equity awards to replace existing Constellation equity awards (b)	11.30		71
Total purchase price		$	7,365

The number of shares issued excludes 0.7 million shares of stock that are held in a custodian account specifically for the settlement of unvested share-based restricted stock awards. The related share value is excluded from the estimated fair value as these awards have not vested and, therefore, are not in the purchase price.
Includes vested Constellation stock options and restricted stock units converted at fair value to Exelon awards on March 12, 2012. The fair value of the stock options was determined using the Black-Scholes model.

Schedule of Purchase Price Allocation [Table Text Block]

Preliminary Purchase Price Allocation, excluding amortization	Exelon		Generation
Current assets	$	4,936	$	3,638
Property, plant and equipment		9,342		4,054
Unamortized energy contracts		3,218		3,218
Other intangibles, trade name and retail relationships		457		457
Investment in affiliates		1,942		1,942
Pension and OPEB regulatory asset		740		0
Other assets		2,265		1,266
Total assets		22,900		14,575

Current liabilities		3,408		2,804
Unamortized energy contracts		1,722		1,512
Long-term debt, including current maturities		5,632		2,972
Noncontrolling interest		90		90
Deferred credits and other liabilities and preferred securities		4,683		1,933
Total liabilities, preferred securities and noncontrolling interest		15,535		9,311
Total purchase price	$	7,365	$	5,264

Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block]

								Estimated amortization expense
Description	Weighted Average Amortization	Gross		Accumulated Amortization		Net		2013		2014		2015		2016		2017		2018 and Beyond
Unamortized energy contracts, net (a)	1.5	$	1,496	$	(982)	$	514	$	394	$	74	$	19	$	(31)	$	(22)	$	80
Trade name	10.0		243		(20)		223		24		24		24		24		24		103
Retail relationships	12.4		214		(15)		199		19		19		19		19		19		104

Total, net		$	1,953	$	(1,017)	$	936	$	437	$	117	$	62	$	12	$	21	$	287

(a) Includes the fair value of BGE's power and gas supply contracts for which an offsetting Exelon Corporate regulatory asset was also recorded.

Schedule of Restructuring and Related Costs [Text Block]

Year Ended December 31, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	124	$	80	$	14	$	7	$	17
Stock compensation		7		4		1		0		1
Other charges		7		4		1		0		1
Total severance benefits	$	138	$	88	$	16	$	7	$	19

_________________

The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
ComEd established regulatory assets of $16 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.

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

Year Ended December 31, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2011	$	0	$	0	$	0	$	0	$	0
Severance charges (a)		124		38		2		0		11
Stock compensation		7		2		0		0		0
Other charges (b)		7		2		0		0		1
Payments		(27)		(9)		(1)		0		(1)
Balance at December 31, 2012	$	111	$	33	$	1	$	0	$	11

Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. Amounts also include one-time termination benefits of $3 million and $1 million for Exelon and Generation, respectively, which they began to recognize in the second quarter of 2012.
Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services.

Business Acquisition, Pro Forma Information [Table Text Block]

	Generation				Exelon
		Year Ended December 31,				Year Ended December 31,
(unaudited)		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	17,013	$	19,494	$	26,700	$	30,712
Net income attributable to Exelon		1,205		324		2,092		974

Basic Earnings Per Share		n.a.		n.a.	$	2.56	$	1.15
Diluted Earnings Per Share		n.a.		n.a.		2.55		1.14

_________________

The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.
The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.

Schedule Of Business Acquisitions By Acquisition [Text Block]

		Acquisitions
		2011				2010
		Wolf Hollow		Antelope Valley		Exelon Wind
Fair value of consideration transferred
Cash	$	305	$	75	$	893
Plus: Gain on PPA settlement		6		-		-
Contingent consideration		-		-		32

Total fair value of consideration transferred	$	311	$	75	$	925

Recognized amounts of identifiable assets acquired and liabilities assumed

Property, plant and equipment	$	347	$	15	$	700
Inventory		5		-		-
Intangible assets ^(a)		-		190		224
Payable to First Solar, Inc. ^(b)		-		(135)		-
Working capital, net		(5)		-		18
Asset retirement obligations		-		-		(13)
Noncontrolling interest		-				(3)
Other Assets		-		5		(1)

Total net identifiable assets	$	347	$	75	$	925

Bargain purchase gain	$	36	$	-	$	-

(a) See Note 8 - Intangible Assets for additional information.

- Definition

Tabular disclosure of pro forma results of operations for a material business acquisition or series of individually immaterial business acquisitions that are material in the aggregate.

+ References + Details

- Definition

Tabular disclosure of the equity interest issued or issuable in a business acquisition (or series of individually immaterial business acquisitions) planned, initiated, or completed during the period.

+ References + Details

- Definition

Tabular disclosure of a material business combination completed during the period, including background, timing, and recognized assets and liabilities. This table does not include leveraged buyouts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1486-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1392-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph F4
-Subparagraph e
-Appendix F

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Investment in Constellation Energy Nuclear Group, LLC (Tables)

12 Months Ended

Dec. 31, 2012

Equity Method Investments and Joint Ventures Tables [Line Items]

Schedule of total equity in earnings of investment in CENG

		For the Period March 12,
		through December 31,
	2012
Equity investment income	$	83
Amortization of basis difference in CENG		(182)
Total equity in earnings (losses) - CENG	$	(99)

Schedule of summarized income statement information for CENG


	Income/(Expense)			Accounts
	For the Period		Income	Receivable/
	March 12 through		Statement	(Accounts Payable)
Agreement	December 31, 2012		Classification	At December 31, 2012
PPA	$	(793)	Purchased power and fuel	$	(83)
PSAA		3	Operating revenues		-
SSA		42	Operating revenues		5

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Accounts Notes Loans And Financing Receivable Text Block [Abstract]

Schedule Of Accounts Notes Loans And Financing Receivable [Text Block]

2012	Exelon		Generation		ComEd		PECO			BGE

Unbilled customer revenues	$	1,418	$	859	$	213	$	164		$	182
Allowance for uncollectible accounts (a)		(293)		(84)		(70)		(99)	(b)		(40)

2011	Exelon		Generation		ComEd		PECO			BGE

Unbilled customer revenues	$	902	$	493	$	246	$	163		$	194
Allowance for uncollectible accounts (a)		(199)		(29)		(78)		(92)	(b)		(37)

(a) Includes the allowance for uncollectible accounts on customer and other accounts receivable.

(b) Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2012 and 2011, respectively, related to PECO's current installment plan receivables described below.

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property Plant Equipment [Line Items]

Schedule Of Property Plant And Equipment Table [Text Block]

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	90	$	26,576	$	21,716
Electric—generation (a)		1	-	53		19,004		13,682
Gas—transportation and distribution		5	-	90		3,108		1,793
Common—electric and gas		5	-	50		1,029		564
Nuclear fuel (b)		1	-	8		4,815		4,225
Construction work in progress		N/A				1,926		1,110
Other property, plant and equipment (c)		3	-	72		912		439

	Total property, plant and equipment					57,370		43,529
	Less: accumulated depreciation (d)					12,184		10,959

Property, plant and equipment, net					$	45,186	$	32,570

(a) Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.

(b) Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(d) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block]

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.76	%	2.59	%	2.53	%
Electric—generation	3.15	%	3.12	%	2.86	%
Gas	2.03	%	1.73	%	1.75	%
Common—electric and gas	7.61	%	8.05	%	7.25	%

Exelon Generation Co L L C [Member]

Property Plant Equipment [Line Items]

Schedule Of Property Plant And Equipment Table [Text Block]

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—generation (a)		1	-	53	$	19,004	$	13,682
Nuclear fuel (b)		1	-	8		4,815		4,225
Construction work in progress		N/A				1,352		827
Other property, plant and equipment (c)		5	-	57		374		54

	Total property, plant and equipment					25,545		18,788
	Less: accumulated depreciation (d)					6,014		5,313

Property, plant and equipment, net					$	19,531	$	13,475

(a) Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.

(b) Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(d) Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

Commonwealth Edison Co [Member]

Property Plant Equipment [Line Items]

Schedule Of Property Plant And Equipment Table [Text Block]

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	75	$	16,480	$	15,637
Construction work in progress		N/A				294		187
Other property, plant and equipment (a)		72				50		47

	Total property, plant and equipment					16,824		15,871
	Less: accumulated depreciation					2,998		2,750

Property, plant and equipment, net					$	13,826	$	13,121

(a) Represents land held for future use and non utility property.

PECO Energy Co [Member]

Property Plant Equipment [Line Items]

Schedule Of Property Plant And Equipment Table [Text Block]

		Average Service Life
		(years)			2012		2011
Asset Category
Electric—transmission and distribution		5	-	65	$	6,355	$	6,079
Gas—transportation and distribution		5	-	70		1,859		1,793
Common—electric and gas		5	-	50		568		564
Construction work in progress		N/A				76		83
Other property, plant and equipment (a)			50			17		17

	Total property, plant and equipment					8,875		8,536
	Less: accumulated depreciation					2,797		2,662

Property, plant and equipment, net					$	6,078	$	5,874

(a) Represents land held for future use and non utility property.

Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block]

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.51	%	2.33	%	2.17	%
Gas	1.77	%	1.73	%	1.75	%
Common—electric and gas	7.54	%	8.05	%	7.25	%

Baltimore Gas and Electric Company [Member]

Property Plant Equipment [Line Items]

Schedule Of Property Plant And Equipment Table [Text Block]

	Average Service Life
	(years)			2012		2011
Asset Category
Electric—transmission and distribution	5	-	90	$	5,767	$	5,483
Gas—transmission and distribution	5	-	90		1,548		1,387
Common—electric and gas	5	-	40		554		415
Construction work in progress	N/A				193		298
Other property, plant and equipment (a)	20				31		15

Total property, plant and equipment					8,093		7,598
Less: accumulated depreciation					2,595		2,466

Property, plant and equipment, net				$	5,498	$	5,132

(a) Represents land held for future use and non utility property.

Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block]

Average Service Life Percentage by Asset Category	2012		2011		2010

Electric—transmission and distribution	2.92	%	2.89	%	2.88	%
Gas	2.33	%	2.41	%	2.42	%
Common—electric and gas	7.68	%	8.40	%	7.24	%

Jointly Owned Electric Utility Plant (Tables)

12 Months Ended

Dec. 31, 2012

Jointly Owned Utility Plant Net Ownership Amount Tables [Line Items]

Schedule Of Jointly Owned Utility Plants Text Block

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

Exelon Generation Co L L C [Member]

Jointly Owned Utility Plant Net Ownership Amount Tables [Line Items]

Schedule Of Jointly Owned Utility Plants Text Block

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

PECO Energy Co [Member]

Jointly Owned Utility Plant Net Ownership Amount Tables [Line Items]

Schedule Of Jointly Owned Utility Plants Text Block

		Nuclear generation									Fossil fuel generation									Transmission					Other

					Peach
		Quad Cities			Bottom			Salem (a)			Keystone (b)			Conemaugh (b)			Wyman			PA (c)		DE/NJ (d)			Other (e)

Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00		%	50.00		%	42.59		%	41.98		%	31.28		%	5.89		%	Various		42.55		%	44.24		%

Exelon’s share at
	December 31, 2012:
Plant (f)		$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated
	depreciation (f)		187			302			119			153			158			3			7		33			—
Construction
	work in progress		44			115			11			10			57			—			1		—			—

Exelon’s share at
	December 31, 2011:
Plant (f)		$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated
	depreciation (f)		156			285			103			137			154			3			3		33			—
Construction
	work in progress		37			111			61			5			15			—			—		—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2012 and 2011.

(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 for additional information.

(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f) Excludes asset retirement costs.

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Goodwill And Intangible Assets [Line Items]

Schedule Of Goodwill Text Block

	2012 and 2011
			Accumulated
	Gross		Impairment		Carrying
	Amount(a)		Losses		Amount

Balance, January 1,	$	4,608	$	1,983	$	2,625

Impairment losses		0		0		0

Balance, December 31,	$	4,608	$	1,983	$	2,625

__________

Schedule of Finite-Lived Intangible Assets [Table Text Block]

								Estimated amortization expense
		Gross		Accumulated Amortization		Net		2013		2014		2015		2016		2017
Generation
	Exelon Wind acquisition (a)	$	224	$	(26)	$	198	$	14	$	14	$	14	$	14	$	14
	Antelope Valley acquisition (b)		190		0		190		7		8		8		8		8
ComEd
	Chicago settlement – 1999 agreement (c)		100		(72)		28		3		3		3		3		4
	Chicago settlement – 2003 agreement (d)		62		(34)		28		4		4		4		4		3

Total intangible assets		$	576	$	(132)	$	444	$	28	$	29	$	29	$	29	$	29

__________

(a) Refer to Note 4 – Merger and Acquisitions for additional information regarding Exelon Wind.

(b) Refer to Note 4 – Merger and Acquisitions for additional information regarding Antelope Valley.

Schedule Of Finite-Lived Intangible Assets Amortization Expense [Text Block]

For the Year Ended December 31,	Exelon		Generation		ComEd

2012	$	20	$	13	$	7
2011		19		12		7
2010		8		1		7

Commonwealth Edison Co [Member]

Schedule Of Goodwill And Intangible Assets [Line Items]

Schedule Of Goodwill Text Block

	2012 and 2011
			Accumulated
	Gross		Impairment		Carrying
	Amount(a)		Losses		Amount

Balance, January 1,	$	4,608	$	1,983	$	2,625

Impairment losses		0		0		0

Balance, December 31,	$	4,608	$	1,983	$	2,625

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References + Details

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Fair Value Tables [Line Items]

Fair value of financial liabilities recorded at the carrying amount

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	214	$	4	$	210	$	0	$	737	$	737
Long-term debt (including amounts
	due within one year)		18,745		0		20,244		276		12,627		14,488
Long-term debt to financing trusts			648		0		0		664		390		358
SNF obligation			1,020		0		763		0		1,019		886
Preferred securities of subsidiary			87		0		82		0		87		79

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

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	995	$	-	$	-	$	995
Nuclear decommissioning trust fund investments
Cash equivalents		245		-		-		245
Equity
Equity securities		1,480		-		-		1,480
Commingled funds		-		1,933		-		1,933
Equity funds subtotal		1,480		1,933		-		3,413
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,057		-		-		1,057
Debt securities issued by states of the United States
and political subdivisions of the states		-		321		-		321
Debt securities issued by foreign governments		-		93		-		93
Corporate debt securities		-		1,788		-		1,788
Federal agency mortgage-backed securities		-		24		-		24
Commercial mortgage-backed securities (non-agency)		-		45		-		45
Residential mortgage-backed securities (non-agency)		-		11		-		11
Mutual funds		-		23		-		23
Fixed income subtotal		1,057		2,305		-		3,362
Middle market lending		-		-		183		183
Other debt obligations		-		15		-		15
Nuclear decommissioning trust fund investments subtotal^(b)		2,782		4,253		183		7,218

Pledged assets for Zion decommissioning
Cash equivalents		-		23		-		23
Equity securities		14		-		-		14
Commingled funds		-		9		-		9
Equity funds subtotal		14		9		-		23
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		118		12		-		130
Debt securities issued by states of the United States						-
and political subdivisions of the states		-		37		-		37
Corporate debt securities		-		249		-		249
Federal agency mortgage-backed securities		-		49		-		49
Commercial mortgage-backed securities (non-agency)		-		6		-		6
Fixed income subtotal		118		353		-		471
Middle market lending		-		-		89		89
Other debt obligations		-		1		-		1
Pledged assets for Zion decommissioning subtotal^(c)		132		386		89		607

Rabbi trust investments
Cash equivalents		2		-		-		2
Mutual funds^(d)		69		-		-		69
Rabbi trust investments subtotal		71		-		-		71

Commodity mark-to-market derivative assets
Economic hedges		861		3,173		641		4,675
Proprietary trading		1,042		2,078		73		3,193
Effect of netting and allocation of collateral^(f)		(1,823)		(4,175)		(58)		(6,056)
Commodity mark-to-market assets subtotal^(g)		80		1,076		656		1,812

Interest rate mark-to-market derivative assets		-		114		-		114
Effect of netting and allocation of collateral		-		(51)		-		(51)
Interest rate mark-to-market derivative assets subtotal		-		63		-		63

Other Investments		2		-		17		19

Total assets		4,062		5,778		945		10,785

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041)		(2,289)		(236)		(3,566)
Proprietary trading		(1,084)		(1,959)		(78)		(3,121)
Effect of netting and allocation of collateral^(f)		2,042		4,020		25		6,087
Commodity mark-to-market liabilities subtotal^(g)(h)		(83)		(228)		(289)		(600)

Interest rate mark-to-market derivative liabilities		-		(84)		-		(84)
Effect of netting and allocation of collateral		-		51		-		51
Interest rate mark-to-market derivative liabilities subtotal		-		(33)		-		(33)

Deferred compensation		-		(102)		-		(102)

Total liabilities		(83)		(363)		(289)		(735)

Total net assets	$	3,979	$	5,415	$	656	$	10,050

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	861	$	0	$	0	$	861
Nuclear decommissioning trust fund investments
Cash equivalents		562		0		0		562
Equity
Equity securities		1,275		0		0		1,275
Commingled funds		0		1,822		0		1,822
Equity funds subtotal		1,275		1,822		0		3,097
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,014		33		0		1,047
Debt securities issued by states of the United States
and political subdivisions of the states		0		541		0		541
Debt securities issued by foreign governments		0		16		0		16
Corporate debt securities		0		778		0		778
Federal agency mortgage-backed securities		0		357		0		357
Commercial mortgage-backed securities (non-agency)		0		83		0		83
Residential mortgage-backed securities (non-agency)		0		5		0		5
Mutual funds		0		47		0		47
Fixed income subtotal		1,014		1,860		0		2,874
Middle market lending		0		0		13		13
Other debt obligations		0		18		0		18
Nuclear decommissioning trust fund investments subtotal^(b)		2,851		3,700		13		6,564

Pledged assets for Zion decommissioning
Equity
Equity securities		35		0		0		35
Commingled funds		0		30		0		30
Equity funds subtotal		35		30		0		65
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		54		26		0		80
Debt securities issued by states of the United States
and political subdivisions of the states		0		65		0		65
Corporate debt securities		0		314		0		314
Federal agency mortgage-backed securities		0		121		0		121
Commercial mortgage-backed securities (non-agency)		0		10		0		10
Commingled funds		0		20		0		20
Fixed income subtotal		54		556		0		610
Middle market lending		0		0		37		37
Other debt obligations		0		13		0		13
Pledged assets for Zion decommissioning subtotal^(c)		89		599		37		725

Rabbi trust investments
Cash equivalents		2		0		0		2
Mutual funds^(d)(e)		34		0		0		34
Rabbi trust investments subtotal		36		0		0		36

Commodity mark-to-market derivative assets
Cash flow hedges		0		857		0		857
Economic hedges		0		1,653		124		1,777
Proprietary trading		0		240		48		288
Effect of netting and allocation of collateral^(f)		0		(1,827)		(28)		(1,855)
Commodity mark-to-market assets^(g)		0		923		144		1,067
Interest rate mark-to-market derivative assets		0		15		0		15

Total assets		3,837		5,237		194		9,268

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		0		(13)		0		(13)
Economic hedges		(1)		(1,137)		(119)		(1,257)
Proprietary trading		0		(236)		(28)		(264)
Effect of netting and allocation of collateral^(f)		0		1,295		20		1,315
Commodity mark-to-market liabilities^(h)		(1)		(91)		(127)		(219)
Interest rate mark-to-market liabilities		0		(19)		0		(19)
Deferred compensation		0		(73)		0		(73)

Total liabilities		(1)		(183)		(127)		(311)

Total net assets	$	3,836	$	5,054	$	67	$	8,957

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(e) Excludes $28 million and $25 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

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

For the Year Ended December 31, 2012		Nuclear Decommissioning Trust Fund Investment		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives(b)		Other Investments		Total
Balance as of January 1, 2012		$	13	$	37	$	17		$	0	$	67
Total realized / unrealized gains (losses)
	Included in net income		-		-		(119)	(a)		-		(119)
	Included in other comprehensive income		-		-		-			-		-
	Included in regulatory assets		1		-		39			-		40
	Included in payable for Zion Station decommissioning		-		-		-			-		-
Change in collateral			-		-		(32)			-		(32)
Purchases, sales, issuances and settlements
	Purchases		169		63		334	(c)		17		583
	Sales		-		(11)		-			0		(11)
Transfers into Level 3			-		-		39			0		39
Transfers out of Level 3			-		-		89			-		89

Balance as of December 31, 2012		$	183	$	89	$	367		$	17	$	656
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2012	$	-	$	-	$	37		$	0	$	37

(a) Includes the reclassification of $156 million of realized losses due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(c) Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

(a) Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

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


		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2012	$	(153)	$	34
Change in the unrealized gains relating to assets and liabilities
	held for the year ended December 31, 2012	$	13	$	24

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2011	$	108	$	(8)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the year ended December 31, 2011	$	137	$	(5)

For the Year Ended December 31, 2011		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Total
Balance as of January 1, 2011			$	0	$	0	$	50		$	50
Total realized / unrealized gains (losses)
	Included in income			1		0		99			100
	Included in other comprehensive income			0		0		(25)	(a)		(25)
	Included in regulatory liabilities			2		0		(106)	(b)		(104)
Change in collateral				0		0		6			6
Purchases, sales, issuances and settlements
	Purchases			10		60		10			80
	Sales			0		(23)		0			(23)
Transfers out of Level 3				0		0		(17)			(17)
Balance as of December 31, 2011			$	13	$	37	$	17		$	67
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2011		$	1	$	0	$	131		$	132

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

Type of trade	Fair Value at December 31, 2012 (d)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	473	Discounted Cash Flow	Forward power price	$	14		-	$	79
			Discounted Cash Flow	Forward gas price	$	3.26		-	$	6.27
			Option Model	Volatility percentage		28	%	-		132	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	(6)	Discounted Cash Flow	Forward power price	$	15		-	$	106
			Option Model	Volatility percentage		16	%	-		48	%

Mark-to-market derivatives – Transactions with affiliates (Generation and ComEd) (b)	$	226	Discounted Cash Flow	Marketability reserve		8	%	-		9	%

Mark-to-market derivatives (ComEd)	$	(67)	Discounted Cash Flow	Forward heat rate (c)		8	%	-		9.5	%
				Marketability reserve		3.5	%	-		8.3	%
				Renewable factor		81	%	-		123	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation.
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.
The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012.

Exelon Generation Co L L C [Member]

Fair Value Tables [Line Items]

Fair value of financial liabilities recorded at the carrying amount

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	0	$	0	$	0	$	0	$	2	$	2
Long-term debt (including amounts
	due within one year)		7,483		0		7,591		258		3,677		4,231
SNF obligation			1,020		0		763		0		1,019		886

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

As of December 31, 2012	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	487	$	0	$	0	$	487
Nuclear decommissioning trust fund investments
Cash equivalents		245		0		0		245
Equity
Equity securities		1,480		0		0		1,480
Commingled funds		0		1,933		0		1,933
Equity funds subtotal		1,480		1,933		0		3,413
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,057		0		0		1,057
Debt securities issued by states of the United States and
political subdivisions of the states		0		321		0		321
Debt securities issued by foreign governments		0		93		0		93
Corporate debt securities		0		1,788		0		1,788
Federal agency mortgage-backed securities		0		24		0		24
Commercial mortgage-backed securities (non-agency)		0		45		0		45
Residential mortgage-backed securities (non-agency)		0		11		0		11
Mutual funds		0		23		0		23
Fixed income subtotal		1,057		2,305		0		3,362
Middle market lending		0		0		183		183
Other debt obligations		0		15		0		15
Nuclear decommissioning trust fund investments subtotal(b)		2,782		4,253		183		7,218

Pledged assets for Zion Station decommissioning
Cash equivalents		0		23		0		23
Equity
Equity securities		14		0		0		14
Commingled funds		0		9		0		9
Equity funds subtotal		14		9		0		23
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		118		12		0		130
Debt securities issued by states of the United States and
political subdivisions of the states		0		37		0		37
Corporate debt securities		0		249		0		249
Federal agency mortgage-backed securities		0		49		0		49
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Fixed income subtotal		118		353		0		471
Middle market lending		0		0		89		89
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		132		386		89		607

Rabbi trust investments
Cash equivalents		1		0		0		1
Mutual funds^(d)(e)		13		0		0		13
Rabbi trust investments subtotal		14		0		0		14

Commodity mark-to-market derivative assets
Economic hedges		861		3,173		867		4,901
Proprietary trading		1,042		2,078		73		3,193
Effect of netting and allocation of collateral^(f)		(1,823)		(4,175)		(58)		(6,056)
Commodity mark-to-market assets subtotal^(g)		80		1,076		882		2,038

Interest Rate mark-to-market derivative assets		0		101		0		101
Effect of netting and allocation of collateral		0		(51)		0		(51)
Interest Rate mark-to-market derivative assets subtotal		0		50		0		50

Other investments		2		0		17		19

Total assets		3,497		5,765		1,171		10,433

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041)		(2,289)		(169)		(3,499)
Proprietary trading		(1,084)		(1,959)		(78)		(3,121)
Effect of netting and allocation of collateral^(f)		2,042		4,020		25		6,087
Commodity mark-to-market liabilities subtotal		(83)		(228)		(222)		(533)

Interest rate mark-to-market derivative liabilities		0		(84)		0		(84)
Effect of netting and allocation of collateral		0		51		0		51
Interest rate mark-to-market derivative liabilities subtotal		0		(33)		0		(33)

Deferred compensation		0		(28)		0		(28)

Total liabilities		(83)		(289)		(222)		(594)

Total net assets	$	3,414	$	5,476	$	949	$	9,839

As of December 31, 2011	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	466	$	0	$	0	$	466
Nuclear decommissioning trust fund investments
Cash equivalents		562		0		0		562
Equity
Equity securities		1,275		0		0		1,275
Commingled funds		0		1,822		0		1,822
Equity funds subtotal		1,275		1,822		0		3,097
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,014		33		0		1,047
Debt securities issued by states of the United States and
political subdivisions of the states		0		541		0		541
Debt securities issued by foreign governments		0		16		0		16
Corporate debt securities		0		778		0		778
Federal agency mortgage-backed securities		0		357		0		357
Commercial mortgage-backed securities (non-agency)		0		83		0		83
Residential mortgage-backed securities (non-agency)		0		5		0		5
Mutual funds		0		47		0		47
Fixed income subtotal		1,014		1,860		0		2,874
Middle market lending		0		0		13		13
Other debt obligations		0		18		0		18
Nuclear decommissioning trust fund investments subtotal(b)		2,851		3,700		13		6,564

Pledged assets for Zion Station decommissioning
Equity
Equity securities		35		0		0		35
Commingled funds		0		30		0		30
Equity funds subtotal		35		30		0		65
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		54		26		0		80
Debt securities issued by states of the United States and
political subdivisions of the states		0		65		0		65
Corporate debt securities		0		314		0		314
Federal agency mortgage-backed securities		0		121		0		121
Commercial mortgage-backed securities (non-agency)		0		10		0		10
Commingled funds		0		20		0		20
Fixed income subtotal		54		556		0		610
Middle market lending		0		0		37		37
Other debt obligations		0		13		0		13
Pledged assets for Zion Station decommissioning subtotal^(c)		89		599		37		725

Rabbi trust investments^(d)(e)		4		0		0		4

Commodity mark-to-market derivative assets
Cash flow hedges		0		857		694		1,551
Other derivatives		0		1,653		124		1,777
Proprietary trading		0		240		48		288
Effect of netting and allocation of collateral^(f)		0		(1,827)		(28)		(1,855)
Commodity mark-to-market assets subtotal^(g)		0		923		838		1,761


Total assets		3,410		5,222		888		9,520

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		0		(13)		0		(13)
Other derivatives		(1)		(1,137)		(13)		(1,151)
Proprietary trading		0		(236)		(28)		(264)
Effect of netting and allocation of collateral^(f)		0		1,295		20		1,315
Commodity mark-to-market liabilities subtotal		(1)		(91)		(21)		(113)

Interest rate mark-to-market derivative liabilities		0		(19)		0		(19)
Deferred compensation		0		(18)		0		(18)

Total liabilities		(1)		(128)		(21)		(150)

Total net assets	$	3,409	$	5,094	$	867	$	9,370

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(d) The $13 million mutual funds held by the Rabbi trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(e) Excludes $8 million and $7 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

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

For the Year Ended December 31, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives				Other Investments	Total
Balance as of January 1, 2012		$	13	$	37	$	817			-	$	867
Total unrealized / realized gains (losses)
	Included in income		-		-		(112)	(a)		-		(112)
	Included in other comprehensive income		-		-		(475)	(b)		-		(475)
	Included in noncurrent payables to affiliates		1		-		-			-		1
Change in collateral			-		-		(32)			-		(32)
Purchases, sales, issuances and settlements
	Purchases		169		63		334	(c)		17		583
	Sales		-		(11)		-			-		(11)
Transfers into Level 3			-		-		39					39
Transfers out of Level 3			-		-		89			-		89

Balance as of December 31, 2012		$	183	$	89	$	660		$	17	$	949
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2012	$	-	$	-	$	(12)		$	-	$	(12)

(a) Includes the reclassification of $100 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(c) Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

For the Year Ended December 31, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of January 1, 2011		$	0	$	0	$	1,030		$	1,030
Total realized / unrealized gains (losses)
	Included in income		1		0		99	(a)		100
	Included in other comprehensive income		0		0		(311)	(b)		(311)
	Included in payable for Zion Station decommissioning		2		0		0			2
Changes in collateral			0		0		6			6
Purchases, sales, issuances and settlements
	Purchases		10		60		10			80
	Sales		0		(23)		0			(23)
Transfers out of Level 3 - Liability			0		0		(17)			(17)

Balance as of December 31, 2011		$	13	$	37	$	817		$	867

The amount of total gains included in income attributed to
	the change in unrealized gains related to assets and liabilities as of December 31, 2011	$	1	$	0	$	131		$	132

(a) Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

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

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2012	$	(146)	$	34
Change in the unrealized gains (losses) relating to assets and
	liabilities held for the year ended December 31, 2012	$	(25)	$	13

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the year ended
	December 31, 2011	$	108	$	(8)
Change in the unrealized gains (losses) relating to assets and
	liabilities held for the year ended December 31, 2011	$	137	$	(5)

Commonwealth Edison Co [Member]

Fair Value Tables [Line Items]

Fair value of financial liabilities recorded at the carrying amount

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Long-term debt (including amounts
	due within one year)	$	5,567	$	0	$	6,530	$	18	$	5,665	$	6,540
Long-term debt to financing trust			206		0		0		212		206		184

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

As of December 31, 2012		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	111	$	0	$	0	$	111
Rabbi trust investments
Mutual funds			8		0		0		8
	Rabbi trust investment subtotal		8		0		0		8

Total assets			119		0		0		119

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities (b)(c)			0		0		(293)		(293)

Total liabilities			0		(8)		(293)		(301)

Total net assets (liabilities)		$	119	$	(8)	$	(293)	$	(182)

As of December 31, 2011		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents (a)		$	173	$	0	$	0	$	173
Rabbi trust investments
Cash equivalents			2		0		0		2
Mutual funds			19		0		0		19
	Rabbi trust investment subtotal		21		0		0		21

Total assets			194		0		0		194

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities (b)(c)			0		0		(800)		(800)

Total liabilities			0		(8)		(800)		(808)

Total net assets (liabilities)		$	194	$	(8)	$	(800)	$	(614)

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

Includes $170 million of increases in fair value and $451 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the year ended December 31, 2011. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $110 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2011.

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

For the Year Ended December 31, 2012	Mark-to-Market Derivatives
Balance as of January 1, 2012	$	(800)
Total realized / unrealized gains included in regulatory assets (a)(b)		507
Balance as of December 31, 2012	$	(293)

Twelve Months Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(971)
Total realized / unrealized gains included in regulatory assets (a)(b)		171
Balance as of December 31, 2011	$	(800)

PECO Energy Co [Member]

Fair Value Tables [Line Items]

Fair value of financial liabilities recorded at the carrying amount

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	210	$	0	$	210	$	0	$	225	$	225
Long-term debt (including amounts
	due within one year)		1,947		0		2,264		0		1,972		2,295
Long-term debt to financing trusts			184		0		0		188		184		174
Preferred securities			87		0		82		0		87		79

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

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	346	$	0	$	0	$	346
Rabbi trust investments - mutual funds^(b)(c)		9		0		0		9

Total assets		355		0		0		355

Liabilities
Deferred compensation obligation		0		(18)		0		(18)

Total liabilities		0		(18)		0		(18)

Total net assets (liabilities)	$	355	$	(18)	$	0	$	337

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	175	$	0	$	0	$	175
Rabbi trust investments - mutual funds^(b)(c)		9		0		0		9

Total assets		184		0		0		184

Liabilities
Deferred compensation obligation		0		(21)		0		(21)

Total liabilities		0		(21)		0		(21)

Total net assets (liabilities)	$	184	$	(21)	$	0	$	163

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b) The mutual funds held by the Rabbi trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(c) Excludes $13 million of the cash surrender value of life insurance investments at December 31, 2012 and 2011, respectively.

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

Year Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(9)
Total realized gains included in regulatory assets		9	(a)
Balance as of December 31, 2011	$	0

Baltimore Gas and Electric Company [Member]

Fair Value Tables [Line Items]

Fair value of financial liabilities recorded at the carrying amount

		December 31, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Long-term debt (including amounts
	due within one year)	$	2,178	$	0	$	2,468	$	0	$	2,101	$	2,377
Long-term debt to financing trusts			258		0		0		263		258		256

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

As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	33	$	0	$	0	$	33
Rabbi trust investments - mutual funds		5		0		0		5

Total assets		38		0		0		38

Liabilities
Deferred compensation obligation		0		(5)		0		(5)

Total liabilities		0		(5)		0		(5)

Total net assets (liabilities)	$	38	$	(5)	$	0	$	33

As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	33	$	0	$	0	$	33

Total assets		33		0		0		33

Liabilities


Total net assets (liabilities)	$	33	$	0	$	0	$	33

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Derivative Financial Instruments Tables [Abstract]

Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense

		Generation										Other		Exelon
Description		Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading (a)		Collateral and Netting (b)		Subtotal		Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	-	$	3	$	20	$	(19)	$	4	$	-	$	4
Mark-to-market derivative assets (Noncurrent Assets)		38	$	8	$	32		(32)		46		13		59
Total mark-to-market derivative assets	$	38	$	11	$	52	$	(51)	$	50	$	13	$	63

Mark-to-market derivative liabilities (Current Liabilities)	$	(1)	$	(1)	$	(19)	$	19	$	(2)	$	0	$	(2)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(31)	$	0	$	(32)		32		(31)		0		(31)
Total mark-to-market derivative liabilities	$	(32)	$	(1)	$	(51)	$	51	$	(33)	$	0	$	(33)

Total mark-to-market derivative net assets (liabilities)	$	6	$	10	$	1	$	0	$	17	$	13	$	30

		Gain (Loss) on Swaps						Gain (Loss) on Borrowings
		Twelve Months Ended						Twelve Months Ended
		December 31,						December 31,
Income Statement Classification		2012		2011		2010		2012		2011		2010
Interest expense (a)	$	(6)	$	1	$	4	$	(6)	$	(1)	$	(4)

______ ____

For the year ended December 31, 2012, the loss on the swaps in the table above includes $12 million reclassified to earnings, with an immaterial amount excluded from hedge effectiveness testing.

Summary of the derivative fair value

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 interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and collateral.

		Generation								ComEd				Exelon
		Generation								ComEd				Exelon
						Collateral
		Economic		Proprietary		and				Economic		Intercompany		Total
Derivatives		Hedges (a)		Trading		Netting(b)		Subtotal (c)		Hedges (a)(d)		Eliminations (a)		Derivatives

Mark-to-market
	derivative assets (current assets)	$	2,883	$	2,469	$	(4,418)	$	934	$	0	$	0	$	934
Mark-to-market
	derivative assets with affiliate (current assets)		226		0		0		226		0		(226)		0
Mark-to-market
	derivative assets (noncurrent assets)		1,792		724		(1,638)		878		0		0		878

Total mark-to-market
	derivative assets	$	4,901	$	3,193	$	(6,056)	$	2,038	$	0	$	(226)	$	1,812

Mark-to-market
	derivative liabilities (current liabilities)	$	(2,419)	$	(2,432)	$	4,519	$	(332)	$	(18)	$	0	$	(350)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		(226)		226		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(1,080)		(689)		1,568		(201)		(49)		0		(250)

Total mark-to-market
	derivative liabilities	$	(3,499)	$	(3,121)	$	6,087	$	(533)	$	(293)	$	226	$	(600)

Total mark-to-market
	derivative net assets (liabilities)	$	1,402	$	72	$	31	$	1,505	$	(293)	$	0	$	1,212

__________

(b) Represents the netting of fair value balances with the same counterparty and the application of collateral.

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

		Generation										ComEd		Other				Exelon
		Generation										ComEd		Other				Exelon
								Collateral
		Cash Flow		Economic		Proprietary		and				Economic		Economic		Intercompany		Total
	Derivatives	Hedges (a)		Hedges		Trading		Netting(b)		Subtotal (c)		Hedges (a) (d)		Hedges		Eliminations (a)		Derivatives
Mark-to-market
	derivative assets (current assets)	$	438	$	1,195	$	217	$	(1,418)	$	432	$	0	$	0	$	0	$	432
Mark-to-market
	derivative assets with affiliate (current assets)		503		0		0		0		503		0		0		(503)		0
Mark-to-market
	derivative assets (noncurrent assets)		419		582		71		(437)		635		0		15		0		650
Mark-to-market
	derivative assets with affiliate (noncurrent assets)		191		0		0		0		191		0		0		(191)		0

Total mark-to-market
	derivative assets	$	1,551	$	1,777	$	288	$	(1,855)	$	1,761	$	0	$	15	$	(694)	$	1,082

Mark-to-market
	derivative liabilities (current liabilities)	$	(9)	$	(965)	$	(194)	$	1,065	$	(103)	$	(9)	$	0	$	0	$	(112)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		0		(503)		0		503		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(4)		(186)		(70)		250		(10)		(97)		0		0		(107)
Mark-to-market
	derivative liability with affiliate (noncurrent liabilities)		0		0		0		0		0		(191)		0		191		0

Total mark-to-market
	derivative liabilities	$	(13)	$	(1,151)	$	(264)	$	1,315	$	(113)	$	(800)	$	0	$	694	$	(219)

Total mark-to-market
	derivative net assets (liabilities)	$	1,538	$	626	$	24	$	(540)	$	1,648	$	(800)	$	15	$	0	$	863

__________

(b) Represents the netting of fair value balances with the same counterparty and the application of collateral.

(d) 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

Total Cash Flow Hedge OCI Activity, Net of Income Tax

Generation

Exelon

Income Statement Location

Energy Related Hedges

Total Cash Flow Hedges

Accumulated OCI derivative gain at

January 1, 2011

1,011

(a)(d)

400

Effective portion of changes in fair value

504

(b)

402

(e)

Reclassifications from accumulated OCI to

net income

Operating Revenues

(585)

(c)

(309)

Ineffective portion recognized in income

Purchased Power

(5)

Accumulated OCI derivative gain at

December 31, 2011

925

(a)(d)

488

Effective portion of changes in fair value

432

(b)

330

(e)

Reclassifications from accumulated OCI to

net income

Operating Revenues

(828)

(c)

(453)

Ineffective portion recognized in income

Operating Revenues

Accumulated OCI derivative gain at

December 31, 2012

532

(a)(d)

368

__________

(d) Excludes $20 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2012 and 2011, respectively.

Other Derivatives - Gain (loss) and reclassification

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 are recorded to operating revenues and eliminated in consolidation.
Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues.

Change in fair value and reclassification of derivative contracts

	Generation							Intercompany Eliminations	Exelon
				Purchased
	Operating			Power				Operating
Year Ended December 31, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(362)	$	215	$	(147)	$	(94)	$	(241)
Reclassification to realized at settlement		429		238		667		101		768
Net mark-to-market gains (losses)	$	67	$	453	$	520	$	7	$	527

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	87	$	131	$	218
Reclassification to realized at settlement		(296)		(219)		(515)
Net mark-to-market (losses) (b)	$	(209)	$	(88)	$	(297)

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	258	$	(40)	$	218
Reclassification to realized at settlement		(516)		1		(515)
Net mark-to-market (losses) (b)	$	(258)	$	(39)	$	(297)

	Exelon and Generation
				Purchased
	Operating			Power
Year Ended December 31, 2010 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	389	$	389
Reclassification to realized at settlement		0		(304)		(304)
Net mark-to-market (losses) (b)	$	0	$	85	$	85

		For the Years Ended
	Location on Income	December 31,
	Statement	2012		2011		2010
Change in fair value	Operating Revenue	$	(12)	$	23	$	26
Reclassification to realized at
settlement	Operating Revenue		108		(26)		(24)

Net mark-to-market gains	Operating Revenue	$	96	$	(3)	$	2

Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements

	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of December 31, 2012	Collateral		Collateral (a)		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,984	$	347	$	1,637		1	$	262
Non-investment grade		28		24		4		0		0
No external ratings
Internally rated - investment grade		512		10		502		1		271
Internally rated - non-investment grade		41		3		38		0		0
Total	$	2,565	$	384	$	2,181		2	$	533

Net Credit Exposure by Type of Counterparty	December 31, 2012

Investor-owned utilities, marketers and power producers		$	865
Energy cooperatives and municipalities			786
Financial Institutions			422
Other			108
Total		$	2,181

As of December 31, 2012, credit collateral held from counterparties where Generation had credit exposure included $344 million of cash and $40 million of letters of credit

Credit-Risk Related Contingent Feature		December 31, 2012
Gross Fair Value of Derivative Contracts Containing this Feature (a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b)	Net Fair Value of Derivative Contracts Containing This Feature (c)


($1,849)	$1,426	($423)


Credit-Risk Related Contingent Feature		December 31, 2011
Gross Fair Value of Derivative Contracts Containing this Feature (a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b)	Net Fair Value of Derivative Contracts Containing This Feature (c)


($1,014)	$928	($86)

Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.
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.
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.

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

Debt and Credit Agreements Year-End (Tables)

12 Months Ended

Dec. 31, 2012

Debt Tables [Line Items]

Schedule Of Short Term Debt [Text Block]

	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer		2012 ^(a)		2011 ^(a)		2012		2011	2012		2011
Exelon Corporate	$	500	$	500	$	-	$	161	0.47	%	0.42	%
Generation		5,600		5,600		-		-	0.45	%	0.48	%
ComEd		1,000		1,000		-		-	0.50	%	0.71	%
PECO		600		600		-		-	-		-
BGE		600		400		-		-	0.43	%	0.38	%
Total	$	8,300	$	8,100	$	-	$	161

(a) Equals aggregate bank commitments under revolving and bilateral credit agreements. See discussion below and Credit Agreements table below for items affecting effective program size.

Schedule Of Short Term Borrowing Activity [Text Block]

	2012			2011			2010

Average borrowings	$	199		$	218		$	125
Maximum borrowings outstanding		505			600			346
Average interest rates, computed on a daily basis		0.48	%		0.50	%		0.72	%
Average interest rates, at December 31		n.a.			0.44	%		n.a.

Generation
	2012			2011			2010

Average borrowings	$	4		$	51		$	0
Maximum borrowings outstanding		165			304			0
Average interest rates, computed on a daily basis		0.45	%		0.48	%		n.a.
Average interest rates, at December 31		n.a.			n.a.			n.a.

ComEd
	2012			2011			2010

Average borrowings	$	110		$	36		$	125
Maximum borrowings outstanding		366			407			346
Average interest rates, computed on a daily basis		0.50	%		0.71	%		0.72	%
Average interest rates, at December 31		n.a.			n.a.			n.a.

BGE
	2012			2011			2010

Average borrowings	$	6		$	26		$	1
Maximum borrowings outstanding		76			190			46
Average interest rates, computed on a daily basis		0.43	%		0.38	%		0.39	%
Average interest rates, computed at December 31		n.a.			n.a.			n.a.

Schedule Of Line Of Credit Facilities Text Block



							Available Capacity at December 31, 2012
Borrower	Aggregate Bank Commitment^(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper

Exelon Corporate	$	500	$	—	$	2	$	498	$	498
Generation		5,600		—		1,818		3,782		3,782
ComEd		1,000		—		—		1,000		1,000
PECO		600		—		1		599		599
BGE		600		—		—		600		600
Total	$	8,300	$	—	$	1,821	$	6,479	$	6,479

Schedule Of Credit Agreement Covenants [Text Block]

	Exelon	Generation	ComEd	PECO	BGE

Credit facility threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2012, the interest coverage ratios at the Registrants were as follows:

	Exelon	Generation	ComEd	PECO	BGE

Interest coverage ratio	9.62	14.20	6.14	7.85	5.16

Schedule Of Debt Instruments Text Block

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	1.63	%	-	7.63	%	2012-2042	$	7,397	$	7,522
	Unsecured bonds:		2.80	%	-	6.35	%	2013-2036		1,850		—
	Rate stabilization bonds:		5.72	%	-	5.82	%	2017		332		—
	Senior unsecured notes		2.00	%	-	8.63	%	2014-2063		8,021		4,902
	Notes payable and other ^(c)		6.95	%	-	7.83	%	2012-2020		177		174
	Pollution control notes:
		Fixed rates	4.10	%	-	5.00	%	2014-2042		20		46
	Non-recourse debt:
		Fixed rates	2.33	%	-	5.50	%	2031-2037		238		—
		Variable rates	1.96	%	-	2.77	%	2014-2030		262		—

Total long-term debt										18,297		12,644
	Unamortized debt discount and premium, net									(17)		(32)
	Fair value adjustment									448		—
	Fair value hedge carrying value adjustment, net									17		15
	Long-term debt due within one year									(1,047)		(828)

Long-term debt									$	17,698	$	11,799

Long-term debt to financing trusts^(d)
	Subordinated debentures to ComEd Financing III					6.35	%	2033	$	206	$	206
	Subordinated debentures to PECO Trust III					7.38	%	2028		81		81
	Subordinated debentures to PECO Trust IV					5.75	%	2033		103		103
	Subordinated debentures to BGE Trust					6.20	%	2043		258		—

Total long-term debt to financing trusts									$	648	$	390

(a) Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures.

(b) Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.

(d) Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets.

Schedule Of Maturities Of Long Term Debt [Text Block]

Year	Exelon			Generation		ComEd			PECO			BGE

2013	$	979		$	28	$	252		$	300		$	467
2014		1,483			616		617			250			70
2015		1,613			553		260			—			75
2016		1,041			76		665			—			379
2017		1,462			706		425			—			41
Thereafter		12,367	(a)		5,292		3,574	(b)		1,584	(c)		1,408	(d)

Total	$	18,945		$	7,271	$	5,793		$	2,134		$	2,440

(a) Includes $648 million due to ComEd, PECO and BGE financing trusts.

(b) Includes $206 million due to ComEd financing trust.

(d) Includes $258 million due to BGE financing trust.

Exelon Generation Co L L C [Member]

Debt Tables [Line Items]

Schedule Of Debt Instruments Text Block

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	Senior unsecured notes ^(b)		2.00	%	-	8.63	%	2014-2063	$	6,721	$	3,602
	Pollution control notes:
		Fixed rates	4.10	%	-	5.00	%	2014-2042		20		46
	Non-recourse debt:
		Fixed rates	2.33	%	-	5.50	%	2031-2037		238		—
		Variable rates	1.96	%	-	2.77	%	2014-2030		262		—
	Notes payable and other ^(a)					7.83	%	2012-2020		30		34

Total long-term debt										7,271		3,682
	Fair value adjustment ^(b)									199		—
	Unamortized debt discount and premium, net									13		(5)
	Long-term debt due within one year									(28)		(3)

Long-term debt									$	7,455	$	3,674

(b) Includes $2,007 million of long-term debt to affiliate, comprised of $1,808 million senior unsecured notes and $199 million fair value adjustment.

Commonwealth Edison Co [Member]

Debt Tables [Line Items]

Schedule Of Debt Instruments Text Block

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	1.63	%	-	7.63	%	2012-2042	$	5,447	$	5,547
	Notes payable					6.95	%	2018		140		140

Total long-term debt										5,587		5,687
	Unamortized debt discount and premium, net									(20)		(22)
	Long-term debt due within one year									(252)		(450)

Long-term debt									$	5,315	$	5,215

Long-term debt to financing trust^(c)
	Subordinated debentures to ComEd Financing III					6.35	%	2033	$	206	$	206

(a) Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture.

(b) Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.

(c) Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets.

PECO Energy Co [Member]

Debt Tables [Line Items]

Schedule Of Debt Instruments Text Block

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
	First Mortgage Bonds ^{(a) (b)}:
		Fixed rates	2.38	%	-	5.95	%	2012-2037	$	1,950	$	1,975

Total long-term debt										1,950		1,975
	Unamortized debt discount and premium, net									(3)		(3)
	Long-term debt due within one year									(300)		(375)

Long-term debt									$	1,647	$	1,597

Long-term debt to financing trusts^(c)
	Subordinated debentures to PECO Trust III					7.38	%	2028	$	81	$	81
	Subordinated debentures to PECO Trust IV					5.75	%	2033		103		103

Long-term debt to financing trusts									$	184	$	184

(a) Substantially all of PECO's assets are subject to the lien of its mortgage indenture.

(b) Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.

(c) Amount owed to this financing trust is recorded as debt to financing trust within PECO's Consolidated Balance Sheets.

Baltimore Gas and Electric Company [Member]

Debt Tables [Line Items]

Schedule Of Maturities Of Long Term Debt [Text Block]

								Maturity	December 31,
			Rates					Date	2012		2011

Long-term debt
		Unsecured bonds	2.80	%	-	6.35	%	2013-2036	$	1,850	$	1,710
		Rate stabilization bonds	5.47	%	-	5.82	%	2012-2017		332	$	395

Total long-term debt										2,182		2,105
	Unamortized debt discount and premium, net									(4)		(4)
	Long-term debt due within one year									(467)		(173)

Long-term debt									$	1,711	$	1,928

Long-term debt to financing trusts^(a)
	Subordinated debentures to BGE Capital Trust II					6.20	%	2043	$	258	$	258

Long-term debt to financing trusts									$	258	$	258

Debt and Credit Agreements Quarter-End (Tables)

12 Months Ended

Dec. 31, 2012

Debt Tables [Abstract]

Commercial paper and credit facility borrowings outstanding

	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer		2012 ^(a)		2011 ^(a)		2012		2011	2012		2011
Exelon Corporate	$	500	$	500	$	-	$	161	0.47	%	0.42	%
Generation		5,600		5,600		-		-	0.45	%	0.48	%
ComEd		1,000		1,000		-		-	0.50	%	0.71	%
PECO		600		600		-		-	-		-
BGE		600		400		-		-	0.43	%	0.38	%
Total	$	8,300	$	8,100	$	-	$	161

(a) Equals aggregate bank commitments under revolving and bilateral credit agreements. See discussion below and Credit Agreements table below for items affecting effective program size.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes Tables [Abstract]

Income Tax Expense Benefit Detail [Text Block]

For the Year Ended December 31, 2012		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	37	$	104	$	(40)	$	88	$	(97)
	Deferred		701		326		237		25		101
	Investment tax credit amortization		(11)		(6)		(2)		(2)		(1)
State
	Current		(25)		(12)		6		4		—
	Deferred		(75)		88		38		12		4

	Total	$	627	$	500	$	239	$	127	$	7

For the Year Ended December 31, 2011		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	1	$	431	$	(329)	$	(71)	$	(71)
	Deferred		1,200		435		544		223		130
	Investment tax credit amortization		(12)		(7)		(3)		(2)		(1)
State
	Current		(3)		74		(123)		(37)		—
	Deferred		271		123		161		33		17

	Total	$	1,457	$	1,056	$	250	$	146	$	75

For the Year Ended December 31, 2010		Exelon		Generation		ComEd		PECO		BGE

Included in operations:
Federal
	Current	$	506	$	372	$	(203)	$	464	$	(201)
	Deferred		972		635		496		(276)		279
	Investment tax credit amortization		(12)		(7)		(3)		(2)		(1)
State
	Current		171		65		(22)		87		(2)
	Deferred		21		113		89		(121)		22

	Total	$	1,658	$	1,178	$	357	$	152	$	97

__________

(b) BGE activity represents the activity for the twelve months ended December 31, 2012, 2011 and 2010.

Net interest receivable (payable) as of	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	31	$	(20)	$	107	$	2	$	—
December 31, 2011		74		33		23		28		(1)

Net interest expense (income) for the years ended	Exelon		Generation		ComEd		PECO		BGE

December 31, 2012	$	(1)	$	11	$	(20)	$	(1)	$	9
December 31, 2011		(56)		(40)		(14)		(1)		(3)
December 31, 2010		110		6		57		35		2

Effective Income Tax Rate Reconciliation

For the Year Ended December 31, 2012		Exelon (a)		Generation (a)		ComEd		PECO		BGE (b)

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(3.6)		4.7		4.6		2.0		24.3
	Qualified nuclear decommissioning trust fund income	5.4		9.1		—		—		—
	Tax exempt income	(0.2)		(0.4)		—		—		—
	Health care reform legislation	0.1		—		0.4		—		11.6
	Amortization of investment tax credit, net deferred taxes	(1.1)		(1.3)		(0.4)		(0.3)		(8.6)
	Production tax credits and other credits	(2.2)		(3.7)		—		—		—
	Plant basis differences	(2.4)		—		(0.3)		(11.5)		(9.0)
	Merger expenses (c)	2.4		—		—		—		24.2
	Fines and Penalties	2.6		4.4		—		—		—
	Other	(1.1)		(0.5)		(0.6)		(0.2)		(13.9)

Effective income tax rate		34.9	%	47.3	%	38.7	%	25.0	%	63.6	%

For the Year Ended December 31, 2011		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	4.4		4.5		3.6		(0.5)		5.2
	Qualified nuclear decommissioning trust fund income	0.5		0.7		—		—		—
	Domestic production activities deduction	(0.3)		(0.4)		—		—		—
	Tax exempt income	(0.2)		(0.2)		—		—		—
	Health care reform legislation	(0.2)		—		(1.0)		—		(0.5)
	Amortization of investment tax credit	(0.3)		(0.3)		(0.4)		(0.3)		(0.5)
	Production tax credits	(0.9)		(1.2)		—		—		—
	Plant basis differences	(1.0)		—		(0.3)		(6.9)		(2.0)
	Other	(0.2)		(0.7)		0.6		—		(1.7)

Effective income tax rate		36.8	%	37.4	%	37.5	%	27.3	%	35.5	%

For the Year Ended December 31, 2010		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	3.0		3.7		6.3		(4.7)		5.5
	Qualified nuclear decommissioning trust fund income	1.7		2.3		—		—		—
	Domestic production activities deduction	(1.2)		(1.5)		—		—		—
	Tax exempt income	(0.1)		(0.2)		—		—		—
	Health care reform legislation	1.4		0.7		1.4		1.6		1.1
	Amortization of investment tax credit	(0.3)		(0.2)		(0.4)		(0.4)		(0.4)
	Plant basis differences	—		—		(0.1)		0.2		(1.0)
	Uncertain tax position remeasurement	—		(2.0)		9.0		—		—
	Other	(0.2)		(0.4)		0.2		0.2		(0.4)

Effective income tax rate		39.3	%	37.4	%	51.4	%	31.9	%	39.8	%

Tax Effects Of Temporary Differences [Text Block]

For the Year Ended December 31, 2012			Exelon		Generation		ComEd		PECO		BGE

	Plant basis differences		$	(10,689)	$	(3,545)	$	(3,537)	$	(2,437)	$	(1,553)
	Accrual based contracts			(389)		(389)		—		—		—
	Derivatives and other financial instruments			(392)		(479)		(4)		—		—
	Deferred pension and post-retirement obligation			1,225		(439)		(598)		(11)		(12)
	Nuclear decommissioning activities			(604)		(604)		—		—		—
	Deferred debt refinancing costs			(537)		163		(25)		(4)		(4)
	Tax loss carryforward			421		226		32		14		105
	Tax credit carryforward			226		226		—		—		—
	Investment in CENG			(405)		(419)		—		—		—
	Other, net			(25)		9		(33)		150		(186)

Deferred income tax liabilities (net)			$	(11,169)	$	(5,251)	$	(4,165)	$	(2,288)	$	(1,650)
Unamortized investment tax credits				(251)		(216)		(24)		(3)		(6)

Total deferred income tax liabilities (net) and
	unamortized investment tax credits		$	(11,420)	$	(5,467)	$	(4,189)	$	(2,291)	$	(1,656)

For the Year Ended December 31, 2011			Exelon		Generation		ComEd		PECO		BGE

	Plant basis differences		$	(7,803)	$	(2,670)	$	(3,264)	$	(2,238)	$	(1,220)
	Unrealized gains on derivative financial
		instruments		(468)		(737)		(4)		—		—
	Deferred pension and post-retirement obligation			665		(520)		(623)		(31)		(93)
	Nuclear decommissioning activities			(452)		(452)		—		—		—
	Deferred debt refinancing costs			(37)		—		(31)		(6)		(4)
	Other, net			41		338		16		135		(226)

Deferred income tax liabilities (net)			$	(8,054)	$	(4,041)	$	(3,906)	$	(2,140)	$	(1,543)
Unamortized investment tax credits				(200)		(169)		(26)		(5)		(8)

Total deferred income tax liabilities (net) and
	unamortized investment tax credits		$	(8,254)	$	(4,210)	$	(3,932)	$	(2,145)	$	(1,551)

Summary Of Loss Carryforwards [Text Block]

		Exelon			Generation			ComEd		PECO			BGE

Federal
Federal net operating loss	$	635	(a)	$	303		$	91	$	0		$	154
Federal capital loss carryforward		178	(b)		178			0		0			0
Federal general business credits carryforward		226	(c)		226			0		0			0

State
State net operating loss		3,365	(d)		1,649	(f)		0		209	(h)		950	(i)
State capital loss carryforward		127	(e)		119	(g)		0		0			0
Deferred taxes on state tax attributes (net)		187			99			0		14			51
Valuation allowance on state tax attributes		36			35			0		0			1

__________

Exelon's federal net operating loss will expire beginning in 2033
Exelon's federal capital loss carryforwards will expire beginning in 2018
Exelon's federal general business credit carryforwards will expire beginning in 2033
Exelon's state net operating losses will expire beginning in 2014
Exelon's state capital loss carryforwards will expire beginning in 2018
Generation's state net operating losses will expire beginning in 2014
Generation's state capital loss carryforwards will expire beginning in 2018
PECO's state net operating losses will expire beginning in 2032
BGE's state net operating losses will expire beginning in 2026

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns Roll Forward [Text Block]

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2012	$	807	$	683	$	70	$	48	$	11
Merger Balance Transfer		195		183		—		—		—
Increases based on tax positions related to 2012		34		3		—		—		—
Change to positions that only affect timing		(88)		(69)		(3)		(4)		(11)
Increases based on tax positions prior to 2012		91		91		—		—		—
Decreases based on tax positions prior to 2012		(6)		(6)		—		—		—
Decreases related to settlements with taxing authorities		(2)		(2)		—		—		—
Decreases from expiration of statute of limitations		(7)		(7)		—		—		—

Unrecognized tax benefits at December 31, 2012	$	1,024	$	876	$	67	$	44	$	—

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2011	$	787	$	664	$	72	$	44	$	73
Increases based on tax positions related to 2011		5		1		—		4		—
Change to positions that only affect timing		21		24		(2)		—		(62)
Decreases based on tax positions prior to 2011		(3)		(3)		—		—		—
Decrease from expiration of statute of limitations		(3)		(3)		—		—		—

Unrecognized tax benefits at December 31, 2011	$	807	$	683	$	70	$	48	$	11

	Exelon		Generation		ComEd		PECO		BGE

Unrecognized tax benefits at January 1, 2010	$	1,498	$	633	$	471	$	372	$	112
Increases based on tax positions related to 2010		1		—		—		—		—
Decreases based on tax positions related to 2010		(2)		(2)		—		—		—
Change to positions that only affect timing		(262)		55		(3)		(328)		(39)
Increases based on tax positions prior to 2010		8		8		—		—		—
Decreases based on tax positions prior to 2010		(3)		(3)		—		—		—
Decreases related to settlements with taxing authorities		(452)		(26)		(396)		—		—
Decrease from expiration of statute of limitations		(1)		(1)		—		—		—

Unrecognized tax benefits at December 31, 2010	$	787	$	664	$	72	$	44	$	73

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations Tables [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

		Exelon and Generation
Nuclear decommissioning ARO at January 1, 2011	$	3,276
Accretion expense		209
Net increase due to changes in, and timing of, estimated future cash flows		198
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2011 (a)		3,680
Accretion expense		231
Net increase due to changes in, and timing of, estimated future cash flows		833
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2012 (a)	$	4,741

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
		For the Years Ended December 31,
		2012		2011		2010

Net unrealized gains (losses) on decommissioning
	trust funds — Regulatory Agreement Units (a) (b) (c)	$	386	$	(74)	$	294
Net unrealized gains (losses) on decommissioning
	trust funds — Non-Regulatory Agreement Units (c)		105		(4)		104

__________

(c) Net unrealized gains (losses) related to Generation's NDT funds are included within other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Non-nuclear asset retirement obligation rollforward

		Exelon		Generation			ComEd		PECO		BGE

Non-nuclear AROs at January 1, 2011		$	223	$	86	$	105	$	32	$	1
Net decrease due to changes in, and timing of,
	estimated future cash flows (a)		(24)		(3)		(17)		(4)		—
Development projects			7		7		—		—		—
Accretion expense (b)			9		5		3		1		—
Payments			(6)		(3)		(2)		(1)		—

Non-nuclear AROs at December 31, 2011			209		92		89		28		1
Net increase due to changes in, and timing of,
	estimated future cash flows (a)		27		18		8		1		7
Development projects			47		47		—		—		—
Accretion expense(b)			13		8		4		1		—
Merger with Constellation (c)			58		50
Payments			(11)		(8)		(2)		(1)		—

Non-nuclear AROs at December 31, 2012		$	343	$	207	$	99	$	29	$	8

During the year ended December 31, 2011, PECO recorded a reduction in operating and maintenance expense of $3 million. Generation and ComEd did not record any reductions in operating and maintenance expense for the year ended December 31, 2011. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2012.
For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information.

Zion Station pledged assets

	Exelon and Generation
	2012		2011
Carrying value of Zion Station pledged assets	$	614	$	734

Payable to Zion Solutions (a)		564		691

Current portion of payable to Zion Solutions (b)		132		128

Withdrawals by Zion Solutions to pay decommissioning costs		192		143

(b) Included in other current liabilities within Generation's Consolidated Balance Sheets

Nuclear Decommissioning (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Nuclear Decommissioning [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

		Exelon and Generation
Nuclear decommissioning ARO at January 1, 2011	$	3,276
Accretion expense		209
Net increase due to changes in, and timing of, estimated future cash flows		198
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2011 (a)		3,680
Accretion expense		231
Net increase due to changes in, and timing of, estimated future cash flows		833
Costs incurred to decommission retired plants		(3)

Nuclear decommissioning ARO at December 31, 2012 (a)	$	4,741

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
		For the Years Ended December 31,
		2012		2011		2010

Net unrealized gains (losses) on decommissioning
	trust funds — Regulatory Agreement Units (a) (b) (c)	$	386	$	(74)	$	294
Net unrealized gains (losses) on decommissioning
	trust funds — Non-Regulatory Agreement Units (c)		105		(4)		104

__________

(c) Net unrealized gains (losses) related to Generation's NDT funds are included within other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Retirement Benefits Tables [Abstract]

Schedule Of Pension And Other Postretirement Participation [Text Block]

		Operating Company
Name of Plan:		Generation	ComEd	PECO	BGE	BSC
Qualified Pension Plans:
Exelon Corporation Retirement Program		X	X	X		X
Exelon Corporation Cash Balance Pension Plan		X	X	X		X
Exelon Corporation Pension Plan for
	Bargaining Unit Employees	X	X			X
Exelon New England Union Employees Pension Plan		X
Exelon Employee Pension Plan for Clinton,
	TMI and Oyster Creek	X	X			X
Pension Plan of Constellation Energy Group, Inc.		X			X	X
BG New England Union Employees Pension Plan		X

Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan
	and 2000 Excess Benefit Plan	X	X	X		X
Exelon Corporation Supplemental Management
	Retirement Plan	X	X	X		X
Benefits Restoration Plan of Constellation Energy Group		X			X	X
Senior Executive Supplemental Pension Plan		X			X	X

Other Postretirement Benefit Plans:
PECO Energy Company Retiree Medical Plan		X		X		X
Exelon Corporation Health Care Program		X	X			X
Exelon Corporation Employees' Life Insurance Plan		X	X	X		X
Constellation Energy Group, Inc. Retiree Medical Plan		X			X	X
Constellation Energy Group, Inc. Retiree Dental Plan		X			X	X
Constellation Energy Group, Inc. Life Insurance Plan
	and Family Life Insurance Plan	X			X
BG New England Post-Employment Medical Savings
	Account Plan	X

Defined Benefit Plan Change In Benefit Obligation RollForward [Text Block]

					Other
	Pension Benefits				Postretirement Benefits
	2012		2011		2012		2011
Change in benefit obligation:
Net benefit obligation at beginning of year	$	13,538	$	12,524	$	4,062	$	3,874
Service cost		280		212		156		142
Interest cost		698		649		205		207
Plan participants’ contributions		0		0		34		25
Actuarial loss		1,520		807		313		4
Plan amendments		0		0		(103)		—
Acquisitions/divestitures		1,880				362
Curtailments		(10)		0		(8)		—
Settlements		(169)		0		—		—
Contractual termination benefits		15		0		6		—
Gross benefits paid		(952)		(654)		(219)		(201)
Federal subsidy on benefits paid		—		—		12		11

Net benefit obligation at end of year	$	16,800	$	13,538	$	4,820	$	4,062

Change in plan assets:
Fair value of net plan assets at beginning of year	$	11,302	$	8,859	$	1,797	$	1,655
Actual return on plan assets		1,484		1,003		197		29
Employer contributions		149		2,094		325		277
Plan participants’ contributions		0		0		34		25
Benefits paid ^(a)		(952)		(654)		(218)		(189)
Acquisitions/divestitures		1,543		—		0		—
Settlements		(169)		—		0		—

Fair value of net plan assets at end of year	$	13,357	$	11,302	$	2,135	$	1,797

Defined Benefit Plan Pension Plans With Projected Benefit Obligations And Accumulated Benefit Obligations In Excess Of Plan Assets [Text Block]

	PBO in excess of plan assets
	2012		2011

Projected benefit obligation	$	16,800	$	13,538
Fair value of net plan assets		13,357		11,302


	ABO in excess of plan assets
	2012		2011

Projected benefit obligation	$	16,796	$	13,538
Accumulated benefit obligation		15,657		12,616
Fair value of net plan assets		13,353		11,302

Schedule of Defined Benefit Plans Disclosures [Text Block]

		Pension Benefits						Other Postretirement Benefits
		2012		2011		2010		2012		2011		2010
Components of net periodic benefit
	cost:
Service cost		$	280	$	212	$	190	$	156	$	142	$	124
Interest cost			698		649		660		205		207		214
Expected return on assets			(988)		(939)		(799)		(115)		(111)		(109)
Amortization of:
	Transition obligation		—		—		—		11		9		9
	Prior service cost (credit)		15		14		14		(17)		(38)		(56)
	Actuarial loss		450		331		254		81		66		74
Curtailment charges			—		0		0		(7)		—		—
Settlement charges			31		0		5		—		—		—
Contractual termination benefits (a)			14		—		—		6		—		1

Net periodic benefit cost		$	500	$	267	$	324	$	320	$	275	$	257

Prescription Drug Benefit Reduction In Accumulated Postretirement Benefit Obligation For Subsidy [Text Block]

	2012		2011		2010

Amortization of the actuarial experience loss	$	(17)	$	3	$	9
Reduction in current period service cost		0		9		10
Reduction in interest cost on the APBO		0		16		19

Total effect of subsidy on net periodic postretirement benefit cost	$	(17)	$	28	$	38

Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets [Text Block]

		Pension Benefits						Other Postretirement Benefits
		2012		2011		2010		2012		2011		2010
Changes in plan assets and benefit
	obligations recognized in AOCI
	and regulatory assets:
Current year actuarial (gain) loss		$	1,693	$	744	$	737	$	304	$	74	$	—
Amortization of actuarial gain (loss)			(450)		(331)		(254)		(81)		(66)		(74)
Current year prior service (credit) cost			1		—		—		(109)		—		—
Amortization of prior service (cost)
	credit		(15)		(14)		(14)		17		38		56
Current year transition (asset) obligation			—						1
Amortization of transition asset
	(obligation)		—		—		—		(11)		(9)		(9)
Curtailments			(10)		—		—		(1)		—		—
Settlements			(31)		—		(5)		—		—		—

Total recognized in AOCI and
	regulatory assets ^(a)	$	1,188	$	399	$	464	$	120	$	37	$	(27)

Of the $1,188 million related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $464 million related to pension benefits, $310 million and $154 million were recognized in AOCI and regulatory assets, respectively, during 2010. Of the $(27) million related to other postretirement benefits, $(9) million and $(18) million were recognized in AOCI and regulatory assets, respectively, during 2010.

Changes In Plan Assets And Benefit Obligations Not Recognized In OCI And Regulatory Assets [Text Block]

	Pension Benefits				Other Postretirement Benefits
	2012		2011		2012		2011
Transition obligation	$	—	$	—	$	—	$	11
Prior service cost (credit)		76		90		(107)		(16)
Actuarial loss		7,931		6,729		1,185		963

Total ^(a)	$	8,007	$	6,819	$	1,078	$	958

Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year [Text Block]

	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	14	$	(19)
Actuarial loss		568		84

Total ^(a)	$	582	$	65

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Text Block]

	Pension Benefits			Other Postretirement Benefits
	2012	2011	2010	2012	2011	2010
Discount rate	3.92%	4.74%	5.26%	4.00%	4.80%	5.30%
Rate of compensation increase	(a)	3.75%	3.75%	(a)	3.75%	3.75%
Mortality table	IRS required mortality table for 2013 funding valuation	IRS required mortality table for 2012 funding valuation	IRS required mortality table for 2011 funding valuation	IRS required mortality table for 2013 funding valuation	IRS required mortality table for 2012 funding valuation	IRS required mortality table for 2011 funding valuation
Health care cost trend on covered charges	N/A	N/A	N/A	6.50% decreasing to ultimate trend of 5.00% in 2017	6.50% decreasing to ultimate trend of 5.00% in 2017	7.00% decreasing to ultimate trend of 5.00% in 2015

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Text Block]

Pension Benefits

Other Postretirement Benefits

2012

2011

2010

2012

2011

2010

Discount rate

3.71% (a)

5.26%

5.83%

3.72% (a)

5.30%

5.83%

Expected return on plan assets

7.50% (b)

8.00% (b)

8.50% (b)

6.68% (b)

7.08% (b)

7.83% (b)

Rate of compensation increase

3.75%

4.00%

3.75%

4.00%

Mortality table

IRS required mortality table for 2012 funding valuation

IRS required mortality table for 2011 funding valuation

IRS required mortality table for 2010 funding valuation

IRS required mortality table for 2012 funding valuation

IRS required mortality table for 2011 funding valuation

IRS required mortality table for 2010 funding valuation

Health care cost trend on covered charges

N/A

6.50% decreasing to ultimate trend of 5.00% in 2017

7.00% decreasing to ultimate trend of 5.00% in 2015

7.50% decreasing to ultimate trend of 5.00% in 2015

(b) Not applicable to pension and other postretirement benefit plans that do not have plan assets.

Pension And Other Postretirement Benefit Contributions [Text Block]

	Pension Benefits						Other Postretirement Benefits
	2012		2011		2010		2012 (a)		2011 (a)		2010 (a)
Generation	$	48	$	954	$	356	$	135	$	121	$	94
ComEd		25		873		260		119		108		60
PECO		13		110		73		33		28		35
BGE (b)		0		0		0		12		0		0
BSC		63		157		77		24		20		14

Exelon	$	149	$	2,094	$	766	$	323	$	277	$	203

Defined Benefit Plan Estimated Future Benefit Payments [Text Block]

			Other Postretirement
	Pension Benefits		Benefits
2013	$	943	$	197
2014		807		204
2015		891		212
2016		868		220
2017		902		231
2018 through 2022		5,161		1,330

Total estimated future benefit payments through 2022	$	9,572	$	2,394

Schedule Of Pension And Other Postretirement Benefit Costs [Text Block]


For the Year Ended December 31,	Generation		ComEd		PECO		BSC (a)		BGE (b)(c)		Exelon

2012	$	341	$	282	$	50	$	99	$	60	$	820
2011		249		213		32		48		51		542
2010		268		215		46		52		48		581

___________________

These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations.
The amounts included in capital and operating and maintenance expense for the years ended 2012, 2011, and 2010 include $12 million, $51 million, and $48 million, respectively, in costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's capital and operating and maintenance expense for the years ended 2012, 2011, and 2010.
BGE's pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset.

Defined Benefit Plan Weighted Average Asset Allocations And Target Allocations [Text Block]

Pension Plans			Percentage of Plan Assets
			at December 31,
Asset Category	Target Allocation		2012		2011

Equity securities	34	%	35	%	32	%
Fixed income securities	40	%	40		47
Alternative investments (a)	26	%	25		21

Total			100	%	100	%

Other Postretirement Benefit Plans			Percentage of Plan Assets
			at December 31,
Asset Category	Target Allocation		2012		2011

Equity securities	45	%	46	%	37	%
Fixed income securities	40	%	40		53
Alternative investments (a)	15	%	14		10

Total			100	%	100	%

(a) Alternative investments include private equity, hedge funds and real estate.

Defined Benefit Plan Fair Value Of Plan Assets [Text Block]

At December 31, 2012 (a)		Level 1		Level 2		Level 3		Total

Pension plan assets
	Cash equivalents	$	1	$	0	$	0	$	1
	Equity securities:
	Individually held		2,562		0		0		2,562
	Commingled funds		0		1,111		0		1,111
	Mutual funds (c)		323		0		0		323
	Equity securities subtotal		2,885		1,111		0		3,996
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		1,037		0		0		1,037
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		108		0		108
	Foreign debt securities		0		252		0		252
	Corporate debt securities		0		3,330		0		3,330
	Federal agency mortgage-backed securities		0		117		0		117
	Non-Federal agency mortgage-backed securities		0		28		0		28
	Commingled funds		0		274		0		274
	Mutual funds (c)		4		291		0		295
	Derivative instruments (b):
	Assets		0		9		0		9
	Liabilities		0		(21)		0		(21)
	Fixed income securities subtotal		1,041		4,388		0		5,429
	Private equity		0		0		754		754
	Hedge funds		0		1,080		1,235		2,315
	Real estate:
	Individually held		280		0		0		280
	Commingled funds		0		75		0		75
	Real estate funds		0		0		426		426
	Real estate subtotal		280		75		426		781
Pension plan assets subtotal			4,207		6,654		2,415		13,276

Other postretirement benefit plan assets
	Cash equivalents		44		0		0		44
	Equity securities:
	Individually held		198		0		0		198
	Commingled funds		0		530		0		530
	Mutual funds (c)		230		0		0		230
	Equity securities subtotal		428		530		0		958
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		18		0		0		18
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		125		0		125
	Foreign debt securities		0		3		0		3
	Corporate debt securities		0		50		0		50
	Federal agency mortgage-backed securities		0		52		0		52
	Non-Federal agency mortgage-backed securities		0		6		0		6
	Commingled funds		0		271		0		271
	Mutual funds (c)		295		2		0		297
	Fixed income securities subtotal		313		509		0		822
	Private equity		0		0		1		1
	Hedge funds		0		188		12		200
	Real estate:
	Individually held		7		0		0		7
	Commingled funds		0		2		0		2
	Real estate funds		0		6		95		101
	Real estate subtotal		7		8		95		110
Other postretirement benefit plan assets subtotal			792		1,235		108		2,135

Total pension and other postretirement
	benefit plan assets (d) (e)	$	4,999	$	7,889	$	2,523	$	15,411

At December 31, 2011 (a)		Level 1		Level 2		Level 3		Total

Pension plan assets
	Cash equivalents	$	8	$	0	$	0	$	8
	Equity securities:
	Individually held		1,985		0		0		1,985
	Commingled funds		0		858		0		858
	Mutual funds		0		389		0		389
	Equity securities subtotal		1,985		1,247		0		3,232
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		1,616		48		0		1,664
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		88		0		88
	Foreign debt securities		0		224		0		224
	Corporate debt securities		0		2,561		0		2,561
	Federal agency mortgage-backed securities		0		156		0		156
	Non-Federal agency mortgage-backed securities		0		28		0		28
	Commingled funds		0		202		0		202
	Mutual funds		0		277		0		277
	Fixed income securities subtotal		1,616		3,584		0		5,200
	Private equity		0		0		672		672
	Hedge funds (f)		0		0		1,525		1,525
	Real estate:
	Individually held		207		0		0		207
	Commingled funds		0		125		0		125
	Real estate funds		0		0		229		229
	Real estate subtotal		207		125		229		561
Pension plan assets subtotal			3,816		4,956		2,426		11,198

Other postretirement benefit plan assets
	Cash equivalents		73		0		0		73
	Equity securities:
	Individually held		110		0		0		110
	Commingled funds		0		415		0		415
	Mutual funds		0		171		0		171
	Equity securities subtotal		110		586		0		696
	Fixed income securities:
	Debt securities issued by the U.S. Treasury and
	other U.S. government corporations and agencies		26		3		0		29
	Debt securities issued by states of the United States
	and by political subdivisions of the states		0		93		0		93
	Foreign debt securities		0		4		0		4
	Corporate debt securities		0		41		0		41
	Federal agency mortgage-backed securities		0		34		0		34
	Non-Federal agency mortgage-backed securities		0		7		0		7
	Commingled funds		0		385		0		385
	Mutual funds		0		256		0		256
	Fixed income securities subtotal		26		823		0		849
	Private equity		0		0		1		1
	Hedge funds (f)		0		0		157		157
	Real estate
	Individually held		4		0		0		4
	Commingled funds		0		1		0		1
	Real Estate funds		0		0		7		7
	Real estate subtotal		4		1		7		12
Other postretirement benefit plan assets subtotal			213		1,410		165		1,788

Total pension and other postretirement
	benefit plan assets (d)	$	4,029	$	6,366	$	2,591	$	12,986

See Note 9 - Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy.
Derivative instruments have a total notional amount of $2,498 million and $910 million at December 31, 2012 and 2011, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.
In 2012, Exelon reassessed its policy over the criteria that mutual fund investments must meet in order to be categorized within Level 1 of the fair value hierarchy. Therefore, certain mutual fund investments that were categorized within Level 2 in prior periods have been re-categorized as Level 1 investments as of December 31, 2012. The re-categorization of these mutual fund investments resulted in a transfer out of Level 2 of $852 million.
Excludes net assets of $77 million and $43 million at December 31, 2012 and 2011 respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.
Includes fixed income commingled fund assets of $66 million as of December 31, 2012. The fair value of these fixed income commingled fund assets of $69 million, as of December 31, 2011, are excluded from the tables above.
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion.

Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Text Block]


		Hedge funds		Private equity		Real estate		Total

Pension Assets
Balance as of January 1, 2012		$	1,525	$	672	$	229	$	2,426
Actual return on plan assets:
	Relating to assets still held at the reporting date		138		55		24		217
Purchases, sales and settlements:
	Purchases		447		108		134		689
	Sales		(6)		0		0		(6)
	Settlements		(4)		(128)		(28)		(160)
Transfers into (out of) Level 3(a) (b) (c)			(865)		47		67		(751)

Balance as of December 31, 2012		$	1,235	$	754	$	426	$	2,415

Other Postretirement Benefits
Balance as of January 1, 2012		$	157	$	1	$	7	$	165
Actual return on plan assets:
	Relating to assets still held at the reporting date		11		0		3		14
Purchases, sales and settlements:
	Purchases		32		0		91		123
	Sales		0		0		0		0
	Settlements		0		0		(1)		(1)
Transfers into (out of) Level 3 (a) (b) (c)			(188)		0		(5)		(193)

Balance as of December 31, 2012		$	12	$	1	$	95	$	108


		Hedge funds		Private equity		Real estate		Total

Pension Assets
Balance as of January 1, 2011		$	329	$	536	$	179	$	1,044
Actual return on plan assets (d):
	Relating to assets still held at the reporting date		(26)		84		46		104
Purchases, sales and settlements (d):
	Purchases		1,222		121		13		1,356
	Sales		0		0		0		0
	Settlements		0		(69)		(9)		(78)
Transfers into (out of) Level 3			0		0		0		0

Balance as of December 31, 2011		$	1,525	$	672	$	229	$	2,426

Other Postretirement Benefits
Balance as of January 1, 2011		$	5	$	0	$	8	$	13
Actual return on plan assets:
	Relating to assets still held at the reporting date		(3)		0		(1)		(4)
Purchases, sales and settlements:
	Purchases		155		1		0		156
	Sales		0		0		0		0
	Settlements		0		0		0		0
Transfers into (out of) Level 3			0		0		0		0

Balance as of December 31, 2011		$	157	$	1	$	7	$	165

In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's pension plan assets resulting in transfers into Level 3 of $141 million.
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion.
In 2012, the liquidity terms of a certain real estate investment changed to allow redemption within a reasonable period of time from the redemption date which led to a transfer out of Level 3 to Level 2 of $5 million.
Certain prior year amounts have been reclassified for comparative purposes.

Schedule Of Defined Contributions [Text Block]

For the Year Ended December 31,	Exelon		Generation		ComEd		PECO		BGE

2012	$	67	$	30	$	19	$	7	$	7
2011		78		40		22		9		7
2010		81		42		22		9		6

Plant Retirements (Tables)

12 Months Ended

Dec. 31, 2012

Corporate Restructuring And Plant Retirements Tables [Abstract]

Total severance benefits costs, recorded as operating and maintenance expense

Year Ended December 31, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	124	$	80	$	14	$	7	$	17
Stock compensation		7		4		1		0		1
Other charges		7		4		1		0		1
Total severance benefits	$	138	$	88	$	16	$	7	$	19

_________________

The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
ComEd established regulatory assets of $16 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.

Activity of severance obligations for the announced Cromby and Eddystone retirements

Severance Benefits Obligation		Exelon and Generation
Balance at January 1, 2011	$	7

Severance charges recorded		4
Cash payments		(4)

Balance at December 31, 2011		7

Cash payments		(4)

Balance at December 31, 2012	$	3

Preferred Securities (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Redeemable Preferred [Line Items]

Temporary Equity Table [Text Block]

			December 31,

	Redemption Price^(a)		2012		2011	2012		2011

				Shares Outstanding			Dollar Amount
Series (without mandatory redemption)
$4.68 (Series D)	$	104.00	150,000		150,000	$	15	$	15
$4.40 (Series C)		112.50	274,720		274,720		27		27
$4.30 (Series B)		102.00	150,000		150,000		15		15
$3.80 (Series A)		106.00	300,000		300,000		30		30

Total preferred securities			874,720		874,720	$	87	$	87

(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.

Preferred Stock [Text Block]

			December 31,

	Redemption Price^(a)		2012		2011	2012		2011

				Shares Outstanding			Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.36	400,000		400,000	$	40	$	40
6.97%, 1993 Series		100.35	500,000		500,000		50		50
6.70%, 1993 Series		100.67	400,000		400,000		40		40
6.99%, 1995 Series		101.05	600,000		600,000		60		60

Total preference stock			1,900,000		1,900,000	$	190	$	190

Baltimore Gas Electric Company [Member]

Schedule Of Redeemable Preferred [Line Items]

Preferred Stock [Text Block]

			December 31,

	Redemption Price^(a)		2012		2011	2012		2011

				Shares Outstanding			Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.36	400,000		400,000	$	40	$	40
6.97%, 1993 Series		100.35	500,000		500,000		50		50
6.70%, 1993 Series		100.67	400,000		400,000		40		40
6.99%, 1995 Series		101.05	600,000		600,000		60		60

Total preference stock			1,900,000		1,900,000	$	190	$	190

- Definition

Tabular disclosure of temporary equity. Temporary equity is a security with redemption features that are outside the control of the issuer, is not classified as an asset or liability in conformity with GAAP, and is not mandatorily redeemable. Includes any type of security that is redeemable at a fixed or determinable price or on a fixed or determinable date or dates, is redeemable at the option of the holder, or has conditions for redemption which are not solely within the control of the issuer. If convertible, the issuer does not control the actions or events necessary to issue the maximum number of shares that could be required to be delivered under the conversion option if the holder exercises the option to convert the stock to another class of equity. If the security is a warrant or a rights issue, the warrant or rights issue is considered to be temporary equity if the issuer cannot demonstrate that it would be able to deliver upon the exercise of the option by the holder in all cases. Includes stock with put option held by ESOP and stock redeemable by holder only in the event of a change in control of the issuer.

+ References + Details

Common Stock (Tables)

12 Months Ended

Dec. 31, 2012

Common Stock Disclosure Tables [Abstract]

Stock Based Compensation Components [Text Block]

		Year Ended
		December 31,

Components of Stock-Based Compensation Expense		2012		2011		2010

Performance share awards		$	46	$	26	$	6
Stock options			15		8		10
Restricted stock units			50		31		21
Other stock-based awards			4		4		4

Total stock-based compensation expense included in
	operating and maintenance expense		115		69		41

Income tax benefit			(44)		(27)		(16)

Total after-tax stock-based compensation expense		$	71	$	42	$	25

Stock Based Compensation Expense Subsidiaries [Text Block]

	Year Ended
	December 31,

Subsidiaries	2012		(a)	2011		2010

Generation	$	42		$	31	$	21
ComEd		11			5		3
PECO		5			5		3
BGE		5			6		4
BSC (b)		52			28		14

Total	$	115		$	69	$	41

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

Stock Based Compensation Tax Benefit [Text Block]

			Year Ended
			December 31,

			2012		2011		2010
Realized tax benefit when exercised/distributed:

		Stock options	$	3	$	2	$	5
		Restricted stock units		11		8		9
		Performance share awards		7		7		13
		Stock deferral plan		—		1		1

Excess tax benefits included in other financing activities of Exelon’s
	Consolidated Statements of Cash Flows:
		Stock options	$	2	$	1	$	3

Weighted Average Assumptions And Grand Date Fair Value Of Stock Options [Text Block]

	Year Ended December 31,

	2012			2011			2010

Dividend yield		5.28	%		4.84	%		4.56	%
Expected volatility		23.20	%		24.40	%		27.10	%
Risk-free interest rate		1.30	%		2.65	%		2.96	%
Expected life (years)		6.25			6.25			6.25
Weighted average grant date fair value (per share)	$	4.18		$	6.22		$	8.08

Stock Option Activity [Text Block]

		Weighted		Weighted
		Average		Average
		Exercise		Remaining
		Price		Contractual	Aggregate
		(per		Life	Intrinsic
	Shares	share)		(years)	Value

Balance of shares outstanding at December 31, 2011	11,553,761	$	48.49
Options granted	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Options exercised	(1,776,041)		26.41
Options forfeited	(980,986)		42.90
Options expired	(459,104)		49.45

Balance of shares outstanding at December 31, 2012	21,903,781	$	45.91	5.58	$	13

Exercisable at December 31, 2012 (a)	19,943,116	$	46.40	5.25	$	13

(a) Includes stock options issued to retirement eligible employees.

Stock Options Exercised [Text Block]

	Year Ended
	December 31,

	2012		2011		2010

Intrinsic value^(a)	$	19	$	5	$	13
Cash received for exercise price		47		13		24

(a) The difference between the market value on the date of exercise and the option exercise price.

Non Vested Stock Option [Text Block]


		Weighted Average
		Exercise Price
	Shares	(per share)

Nonvested at December 31, 2011 (a)	877,050	$	48.66
Granted (b)	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Vested (b)(c)	(12,023,432)		41.37
Forfeited	(459,104)		49.45

Nonvested at December 31, 2012 (a)	1,960,665	$	40.56

(a) Excludes 2,647,536 and 1,348,000 of stock options issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Includes 8,684,709 of converted Constellation options that were vested prior to the Merger on March 12, 2012.

(c) Includes 1,699,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.

Non Vested Restricted Stock [Text Block]


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	1,074,484	$	48.08
Granted	1,332,214		39.94
Converted Constellation restricted stock	825,735		38.91
Vested	(479,805)		46.36
Forfeited	(76,484)		42.21
Undistributed vested awards (b)	(646,983)		40.75

Nonvested at December 31, 2012 (a)	2,029,161	$	42.12

(a) Excludes 686,121 and 448,827 of restricted stock units issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012.

Non Vested Performance Shares [Text Block]


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	346,848	$	45.37
Granted	1,429,189		39.72
Vested	(167,048)		47.46
Forfeited	(116,388)		39.78
Undistributed vested awards (b)	(179,867)		40.72

Nonvested at December 31, 2012 (a)	1,312,734	$	40.08

(a) Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012.

Not Settled Performance Share Awards Balance Sheet Presentation [Text Block]


	December 31,

	2012		2011

Current liabilities^(a)	$	7	$	3
Deferred credits and other liabilities^(b)		11		—
Common stock		35		30

Total	$	53	$	33

(a) Represents the current liability related to performance share awards expected to be settled in cash.

(b) Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share and Equity (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share and Equity Tables [Abstract]

Reconciliation of basic and diluted earnings per share


	Year Ended December 31,
	2012		2011		2010

Net income on common stock	$	1,160	$	2,495	$	2,563

Weighted average common shares outstanding — basic		816		663		661
Assumed exercise and/or distributions of stock-based awards		3		2		2

Weighted average common shares outstanding — diluted		819		665		663

- Definition

Tabular disclosure of the effect of income (loss) on an entity's diluted earnings per share.

+ References + Details

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies Tables Disclosure [Line Items]

Utility Energy Purchase Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

ComEd
Electric supply procurement(a)	$	1,103	$	367	$	323	$	136	$	137	$	140	$	-
Renewable energy and RECs(b)		1,661		71		73		74		76		82		1,285
PECO
Electric supply procurement(c)		799		561		200		38		-		-		-
AECs		33		12		9		2		2		2		6
BGE
Electric supply procurement(d)		1,401		859		467		75		-		-		-
Curtailment services		153		49		47		41		16		-		-

_________________

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. See Note 3 – Regulatory Matters for additional information.
ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Per the ICC's Final Commission Order on December 19, 2012, the quantities purchased under these long-term renewable contracts should be curtailed during the June 2013 – May 2014 period to avoid exceeding the statutory rate impact for affected customers as a result of an increased number of ComEd's customers purchasing their energy from alternative energy suppliers. See Note 3 – Regulatory Matters for additional information.
PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 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 3 – Regulatory Matters for additional information.
BGE entered into various contracts for the procurement of electricity beginning 2012 through 2015. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 – Regulatory Matters for additional information.

Fuel Purchase Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Generation	$	8,857	$	1,276	$	1,207	$	1,272	$	976	$	1,064	$	3,062
PECO		444		145		87		71		49		15		77
BGE		654		133		73		54		52		52		290

Commercial Commitments [Text Block]

				Expiration within
														2018
		Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)		$	1,889	$	1,325	$	—	$	564	$	—	$	—	$	—
Surety bonds^(b)			286		225		—		1		6		4		50
Performance guarantees ^(c)			1,897		908		203		—		—		—		786
Energy marketing contract
	guarantees (d)		8,556		8,556		—		—		—		—		—
Lease guarantees^(e)			48		—		—		—		—		—		48
Middle market lending commitments^(f)			180		180		—		—		—		—		—
Nuclear insurance premiums ^(g)			2,494		—		—		—		—		—		2,494

Total commercial commitments		$	15,350	$	11,194	$	203	$	565	$	6	$	4	$	3,378

(a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(e) Lease guarantees - Guarantees issued to ensure payments on building leases.

Operating Leases Of Lessee Disclosure [Text Block]

	Exelon			Generation			ComEd (b)		PECO (b)		BGE (b)(c)

2013	$	88		$	38		$	13	$	14	$	12
2014		83			38			11		13		10
2015		73			38			11		3		9
2016		69			36			11		3		7
2017		63			36			6		3		6
Remaining years		488			367			57		—		29

Total minimum future lease payments	$	864	(a)	$	553	(a)	$	109	$	36	$	73

(a) Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments.

Operating Leases Rent Expense [Text Block]

For the Year Ended December 31,	Exelon		Generation (a)		ComEd		PECO		BGE

2012	$	930	$	872	$	18	$	27	$	12
2011		711		659		18		28		15
2010		722		665		19		31		13

Accrued environmental liabilities [Text Block]

	Total environmental investigation			Portion of total related to MGP
December 31, 2012	and remediation reserve			investigation and remediation

Exelon		$	338		$	298
Generation			30			-
ComEd			260			254
PECO			47			44
BGE			1			-

	Total environmental investigation			Portion of total related to MGP
December 31, 2011	and remediation reserve			investigation and remediation

Exelon		$	224		$	168
Generation			47			-
ComEd			127			121
PECO			50			47
BGE			-			-

Other Purchase Obligation [Table Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Exelon	$	716	$	186	$	167	$	114	$	51	$	49	$	149
Generation		487		127		120		94		32		29		85
ComEd		8		2		6		—		—		—		—
PECO		45		17		18		1		1		1		7
BGE		—		—		—		—		—		—		—

Exelon Generation Co L L C [Member]

Commitments And Contingencies Tables Disclosure [Line Items]

Energy Commitments [Text Block]

	Net Capacity			Power-Related			Transmission Rights			Purchased Energy
	Purchases (a)			Purchases (b)			Purchases (c)			from CENG			Total

2013		$	374		$	95		$	28		$	777	$	1,274
2014			353			69			26			516		964
2015			350			25			13			—		388
2016			266			11			2			—		279
2017			203			3			2			—		208
Thereafter			469			5			34			—		508

Total		$	2,015		$	208		$	105		$	1,293	$	3,621

(b) Power-Related Purchases include firm REC purchase agreements. 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.

Commercial Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	1,841	$	1,278	$	—	$	563	$	—	$	—	$	—
Performance guarantees ^(b)		1,153		907		203		—		—		—		43
Energy marketing contract guarantees^(c)		1,794		1,794		—		—		—		—		—
Middle market lending commitments ^(d)		180		180		—		—		—		—		—
Nuclear insurance premiums ^(e)		2,494		—		—		—		—		—		2,494

Total commercial commitments	$	7,462	$	4,159	$	203	$	563	$	—	$	—	$	2,537

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

(b) Performance guarantees - Guarantees issued to ensure performance under specific contracts including $211 million issued on behalf of CENG nuclear generating facilities for credit support.

Commonwealth Edison Co [Member]

Commitments And Contingencies Tables Disclosure [Line Items]

Commercial Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		8		8		—		—		—		—		—
Performance guarantees (c)		200		—		—		—		—		—		200

Total commercial commitments	$	230	$	30	$	—	$	—	$	—	$	—	$	200

(a) Letters of credit (non-debt) - ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c) Reflects full and unconditional guarantees of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

PECO Energy Co [Member]

Commitments And Contingencies Tables Disclosure [Line Items]

Commercial Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		3		3		—		—		—		—		—
Performance guarantees(c)		178		—		—		—		—		—		178

Total commercial commitments	$	203	$	25	$	—	$	—	$	—	$	—	$	178

(a) Letters of credit (non-debt) - PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c) Reflects full and unconditional guarantees of Trust Preferred Securities of PECO Trust III and IV, which is a 100% owned finance subsidiary of PECO.

Baltimore Gas and Electric Company [Member]

Commitments And Contingencies Tables Disclosure [Line Items]

Commercial Commitments [Text Block]

			Expiration within
													2018
	Total		2013		2014		2015		2016		2017		and beyond

Letters of credit (non-debt)^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds (b)		2		2		—		—		—		—		—
Performance guarantees (c)		250		—		—		—		—		—		250

Total commercial commitments	$	254	$	4	$	—	$	—	$	—	$	—	$	250

Letters of credit (non-debt) - BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
Surety bond – Guarantees issued related to contract and commercial agreements, excluding bid bonds.
Reflects full and unconditional guarantees of Trust Preferred Securities of BGE Capital Trust II which is a 100% owned finance subsidiary of BGE.

Supplemental Financial Information (Tables)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Supplemental Financial Information Tables [Line Items]

Components of taxes other than income

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	463	$	82	$	239	$	141	$	75
Property		227		189		22		13		111
Payroll		131		78		26		12		18
Other		198		20		8		(4)		4

Total taxes other than income	$	1,019	$	369	$	295	$	162	$	208

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	443	$	27	$	243	$	173	$	79
Property		177		146		22		9		107
Payroll		123		71		25		13		17
Other		42		20		6		10		4

Total taxes other than income	$	785	$	264	$	296	$	205	$	207

For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	476	$	0	$	205	$	271	$	79
Property		175		142		20		13		102
Payroll		121		70		24		12		16
Other		36		18		7		7		3

Total taxes other than income	$	808	$	230	$	256	$	303	$	200

Components of non-operating income and expenses

For the Year Ended December 31, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	189	$	189	$	0	$	0	$	0
		Non-Regulatory Agreement Units		102		102		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		386		386		0		0		0
		Non-Regulatory Agreement Units		105		105		0		0		0
	Net unrealized gains on pledged assets —
		Zion Station decommissioning		73		73		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(530)		(530)		0		0		0
Total decommissioning-related activities				325		325		0		0		0
Investment income				20		3		1		2		11	(c)
Long-term lease income				29		0		0		0		0
Interest income related to uncertain income tax positions				15		2		20		0		0
AFUDC - Equity				17		0		6		4		10
Credit facility termination fees				(85)		(85)		0		0		0
Other				25		(6)		12		2		2

Other, net			$	346	$	239	$	39	$	8	$	23

For the Year Ended December 31, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	177	$	177	$	0	$	0	$	0
		Non-Regulatory Agreement Units		45		45		0		0		0
	Net unrealized losses on decommissioning trust funds —
		Regulatory Agreement Units		(74)		(74)		0		0		0
		Non-Regulatory Agreement Units		(4)		(4)		0		0		0
	Net unrealized gains on pledged assets —
		Zion Station decommissioning		48		48		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(130)		(130)		0		0		0
Total decommissioning-related activities				62		62		0		0		0
Investment income				10		1		1		3		13	(c)
Long-term lease income				28		0		0		0		0
Interest income related to uncertain income tax positions				53		31		14		1		0
AFUDC - Equity				17		0		8		9		15
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				(3)		(8)		6		1		(2)

Other, net			$	203	$	122	$	29	$	14	$	26

For the Year Ended December 31, 2010			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a) -
		Regulatory Agreement Units	$	176	$	176	$	0	$	0	$	0
		Non-Regulatory Agreement Units		51		51		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		316		316		0		0		0
		Non-Regulatory Agreement Units		104		104		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(394)		(394)		0		0		0
Total decommissioning-related activities				253		253		0		0		0
Investment income				1		0		0		1		15	(c)
Long-term lease income				27		0		0		0		0
Interest income related to uncertain income tax positions				0		0		6		0		0
AFUDC - Equity				11		0		4		7		10
Realized gain on Rabbi trust investments				1		0		1		0		0
Other				19		4		13		0		0

Other, net			$	312	$	257	$	24	$	8	$	25

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

(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 3 – Regulatory Matters for additional information regarding the rate stabilization deferral. )

Components of depreciation, amortization and accretion, and other, net

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,712	$	733	$	525	$	207	$	245
Regulatory assets		129		0		80		10		53
Amortization of intangible assets, net		40		35		5		0		0
Amortization of energy contract assets and liabilities(a)		1,110		1,110		0		0		0
Nuclear fuel(a)		848		848		0		0		0
ARO accretion(b)		240		240		0		0		0

Total depreciation, amortization and accretion	$	4,079	$	2,966	$	610	$	217	$	298

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,284	$	570	$	502	$	191	$	224
Regulatory assets		63		0		52		11		50
Nuclear fuel(a)		755		755		0		0		0
ARO accretion(b)		214		214		0		0		0

Total depreciation, amortization and accretion	$	2,316	$	1,539	$	554	$	202	$	274

For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO			BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,144	$	474	$	473	$	171		$	214
Regulatory assets		931		0		43		889	(c)		35
Nuclear fuel(a)		672		672		0		0			0
ARO accretion(b)		196		195		1		0			0

Total depreciation, amortization and accretion	$	2,943	$	1,341	$	517	$	1,060		$	249

(a) Included in revenues or fuel expense on the Registrants' Consolidated Statements of Operations.

(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations.

Cash Flow Supplemental Disclosures

For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	761	$	286	$	288	$	113	$	136
Income taxes (net of refunds)		(171)		175		(42)		(64)		(112)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	820	$	341	$	282	$	50	$	57
Loss in equity method investments		91		91		0		0		0
Provision for uncollectible accounts		164		22		42		60		44
Provision for obsolete inventory		6		6		1		0		0
Stock-based compensation costs		94		0		0		0		0
Other decommissioning-related activity (a)		(145)		(145)		0		0		0
Energy-related options (b)		160		160		0		0		0
Amortization of regulatory asset related to debt costs		18		0		13		3		2
Amortization of rate stabilization deferral		57		0		0		0		67
Amortization of debt fair value adjustment		(34)		(34)		0		0		0
Merger-related commitments (d)		141		32		0		0		27
Severance cost		99		34		0		0		0
Discrete impacts from Energy Infrastructure
Modernization Act (EIMA) (c)		(96)		0		(96)		0		0
Amortization of debt costs		19		11		5		3		2
Other		(11)		19		5		9		(6)

Total other non-cash operating activities	$	1,383	$	537	$	252	$	125	$	193

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	71	$	0	$	28	$	20	$	26
Other regulatory assets and liabilities		(404)		0		(68)		18		(112)
Other current assets		213		(30)		(7)		(12)		(7)
Other noncurrent assets and liabilities		(248)		(98)		(95)		(10)		8

Total changes in other assets and liabilities	$	(368)	$	(128)	$	(142)	$	16	$	(85)

	Exelon		Generation			ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	781	$	781		$	2	$	0	$	0
Change in capital expenditures not paid		160		103	(e)		15		26		(4)
Merger with Constellation, common stock issued		7,365		5,264			0		0		0

(b) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(d) See Note 4 – Mergers and Acquisitions for more information on merger-related commitments.

(e) Includes $247 million of capital expenditures not paid as of December 31, 2012 related to Antelope Valley.

For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	649	$	158	$	296	$	128	$	122
Income taxes (net of refunds)		(457)		347		(676)		(65)		(54)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	542	$	249	$	213	$	32	$	51
Provision for uncollectible accounts		121		0		57		64		44
Stock-based compensation costs		67		0		0		0		0
Other decommissioning-related activity (a)		16		16		0		0		0
Energy-related options (b)		137		137		0		0		0
Amortization of regulatory asset related to debt costs		21		0		18		3		2
Amortization of rate stabilization deferral		0		0		0		0		57
Deferral of storm costs		0		0		0		0		(16)
Uncollectible accounts recovery, net		14		0		14		0		0
Discrete impacts from 2010 Rate Case order (c)		(32)		0		(32)		0		0
Bargain purchase gain related to Wolf Hollow Acquisition		(36)		(36)		0		0		0
Discrete impacts from Energy Infrastructure
Modernization Act (EIMA) (d)		(82)		0		(82)		0		0
Other		2		55		(4)		1		(9)

Total other non-cash operating activities	$	770	$	421	$	184	$	100	$	129

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(45)	$	0	$	(49)	$	4	$	(52)
Other regulatory assets and liabilities		0		0		44		26		10
Other current assets		(101)		(23)		(14)		(12)		(88)
Other noncurrent assets and liabilities		122		(34)		64		(4)		(31)

Total changes in other assets and liabilities	$	(24)	$	(57)	$	45	$	14	$	(161)

	Exelon		Generation			ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	186	$	186		$	0	$	0	$	0
Change in capital expenditures not paid		96		125	(e)		7		(35)		(7)

(b) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(e) Includes $120 million of capital expenditures not paid as of December 31, 2011 related to Antelope Valley.

For the Year Ended December 31, 2010	Exelon			Generation		ComEd			PECO		BGE

Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	665	^(a)	$	145	$	283		$	168	$	128
Income taxes (net of refunds)		1,219			732		15			433		(76)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	581		$	268	$	215		$	46	$	48
Provision for uncollectible accounts		108			1		48			59		38
Provision for obsolete inventory		12			12		0			0		0
Stock-based compensation costs		44			0		0			0		0
Other decommissioning-related activity^(b)		(91)			(91)		0			0		0
Energy-related options ^(c)		(73)			(73)		0			0		0
ARO adjustment		(19)			(8)		(10)			(1)		0
Amortization of regulatory asset related to debt costs		24			0		20			4		2
Amortization of rate stabilization deferral		0			0		0			0		62
Accrual for Illinois utility distribution tax refund (d)		(25)			0		(25)			0		0
Under-recovered uncollectible accounts, net (e)		(14)			0		(14)			0		0
ARP SO2 allowances impairment		57			57		0			0		0
Other		5			16		4			0		(6)

Total other non-cash operating activities	$	609		$	182	$	238		$	108	$	144

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	61		$	0	$	58		$	3	$	6
Other regulatory assets and liabilities		0			0		(19)			35		(64)
Other current assets		(18)			(16)		12			(19)		(7)
Other noncurrent assets and liabilities		(99)			(29)		(184)	^(f)		59		2

Total changes in other assets and liabilities	$	(56)		$	(45)	$	(133)		$	78	$	(63)

	Exelon		Generation		ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	(428)	$	(428)	$	0	$	0	$	0
Change in capital expenditures not paid		34		13		7		14		28
Purchase accounting adjustments		9		9		0		0		0
Exelon Wind acquisition (g)		32		32		0		0		0

(a) Excludes $167 million of interest paid to the IRS relating to a preliminary agreement reached during the third quarter of 2010. See Note 12 - Income Taxes for addition information.

(c) Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(f) Relates primarily to a decrease in interest payable associated with a change in uncertain income tax positions. See Note 12 - Income Taxes for additional information.

(g) Represents contingent liability recorded in connection with the December 9, 2010 acquisition of Exelon Wind. See Note 4 - Acquisition for additional information.

Investments Table Text Block

December 31, 2012		Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
	Financing trusts^(a)	$	22	$	0	$	6	$	8	$	8
	Keystone Fuels, LLC		38		38		0		0		0
	Conemaugh Fuels, LLC		26		26		0		0		0
	CENG		1,849		1,849		0		0		0
	Safe Harbor		293		293		0		0		0
	Malacha		8		8		0		0		0
	Other investments		34		33		0		0		0

	Total equity method investments		2,270		2,247		6		8		8

Other investments:
	Net investment in direct financing leases		685		0		0		0		0
	Employee benefit trusts and investments^(b)		100		22		8		22		5

Total investments		$	3,055	$	2,269	$	14	$	30	$	13

December 31, 2011		Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
	Financing trusts^(a)	$	15	$	0	$	6	$	8	$	8
	Keystone Fuels, LLC		13		13		0		0		0
	Conemaugh Fuels, LLC		16		16		0		0		0
	Sacramento Solar		1		1		0		0		0

	Total equity method investments		45		30		6		8		8

Other investments:
	Net investment in direct financing leases		656		0		0		0		0
	Employee benefit trusts and investments^(b)		65		11		21		22		0

Total investments		$	766	$	41	$	27	$	30	$	8

(b) The Registrants' investments in these marketable securities are recorded at fair market value.

Capital Leases Net Investment In Direct Financing Leases Table

	December 31,

	2012		2011

Estimated residual value of leased assets	$	1,492	$	1,492
Less: unearned income		807		836

Net investment in long-term leases	$	685	$	656

Accrued Liabilities Current Table

December 31, 2012		Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)		$	708		$	371		$	125	$	45	$	38
Taxes accrued			353			247			61		3		22
Interest accrued			236			60			96		32		41
Severance accrued			91			42			4		1		5
Other accrued expenses			412	(b)		396	(b)		9		1		-

Total accrued expenses		$	1,800		$	1,116		$	295	$	82	$	106




December 31, 2011		Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)		$	520		$	264		$	127	$	48	$	42
Taxes accrued			297			241			59		5		26
Interest accrued			192			56			124		27		41
Severance accrued			15			9			2		1		-
Other accrued expenses			231	(b)		209	(b)		6		2		1

Total accrued expenses		$	1,255		$	779		$	318	$	83	$	110


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
(b)	Includes $327 million and $184 million for amounts accrued related to Antelope Valley as of December 31, 2012 and December 31, 2011, respectively.

Accumulated Other Comprehensive Income Net Of Taxes

December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	367	$	513	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(3,155)		(19)		0		0		0
Unrealized loss on marketable securities		21		19		0		1		0

Total accumulated other comprehensive income (loss)	$	(2,767)	$	513	$	0	$	1	$	0

December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	488	$	915	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(2,938)		0		0		0		0
Unrealized loss on marketable securities		0		0		(1)		0		0

Total accumulated other comprehensive income (loss)	$	(2,450)	$	915	$	(1)	$	0	$	0

Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Schedules Of Segment Reporting Information [Line Items]

Analysis and reconciliation of reportable segment information

												Intersegment
		Generation (a)		ComEd		PECO		BGE(b)		Other(c)		Eliminations			Exelon
Operating revenues^(d):
	2012	$	14,437	$	5,443	$	3,186	$	2,091	$	1,396	$	(3,064)		$	23,489
	2011		10,447		6,056		3,720		-		830		(1,990)			19,063
	2010		10,025		6,204		5,519		-		755		(3,859)			18,644
Intersegment revenues^(e):
	2012	$	1,702	$	2	$	3	$	9	$	1,381	$	(3,042)		$	55
	2011		1,161		2		5		-		831		(1,990)			9
	2010		3,102		2		5		-		756		(3,859)			6
Depreciation and amortization
	2012	$	768	$	610	$	217	$	238	$	46	$	2		$	1,881
	2011		570		554		202		-		21		-			1,347
	2010		474		516		1,060		-		25		-			2,075
Operating expenses^(d):
	2012	$	13,226	$	4,557	$	2,563	$	2,053	$	1,662	$	(3,043)		$	21,018
	2011		7,571		5,074		3,065		-		863		(1,990)			14,583
	2010		6,979		5,148		4,858		-		792		(3,859)			13,918
Equity in earnings (losses) of unconsolidated affiliates
	2012	$	(91)	$	-	$	-	$	-	$	-	$	-		$	(91)
	2011		(1)		-		-		-		-		-			(1)
	2010		-		-		-		-		-		-			-
Interest expense, net:
	2012	$	301	$	307	$	123	$	111	$	86	$	-		$	928
	2011		170		345		134		-		77		-			726
	2010		153		386		193		-		85		-			817
Income (loss) before income taxes:
	2012	$	1,058	$	618	$	508	$	(54)	$	(276)	$	(56)		$	1,798
	2011		2,827		666		535		-		(59)		(13)			3,956
	2010		3,150		694		476		-		(91)		(8)			4,221
Income taxes:
	2012	$	500	$	239	$	127	$	(23)	$	(215)	$	(1)		$	627
	2011		1,056		250		146		-		9		(4)			1,457
	2010		1,178		357		152		-		(27)		(2)			1,658
Net income (loss):
	2012	$	558	$	379	$	381	$	(31)	$	(61)	$	(55)		$	1,171
	2011		1,771		416		389		-		(68)		(9)			2,499
	2010		1,972		337		324		-		(64)		(6)			2,563
Capital expenditures:
	2012	$	3,554	$	1,246	$	422	$	500	$	67	$	-		$	5,789
	2011		2,491		1,028		481		-		42		-			4,042
	2010		1,883		962		545		-		14		(78)	(f)		3,326
Total assets:
	2012	$	40,681	$	22,905	$	9,353	$	7,499	$	10,432	$	(12,316)		$	78,554
	2011		27,433		22,638		9,156		-		6,147		(10,379)			54,995

(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2012.

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

Reconciliation of revenues from segments to consolidated

(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.

Exelon Generation Co L L C [Member]

Schedules Of Segment Reporting Information [Line Items]

Analysis and reconciliation of reportable segment revenues for Generation

Generation total revenues:
	2012						2011						2010
	Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	5,082	$	(44)	$	5,038	$	4,052	$	-	$	4,052	$	3,232	$	-	$	3,232
Midwest		4,824		24		4,848		5,445		-		5,445		5,762		-		5,762
New England		1,048		45		1,093		11		-		11		14		-		14
New York		582		(25)		557		0		-		0		0		-		0
ERCOT		1,365		2		1,367		575		-		575		543		-		543
Other Regions (b)		755		78		833		201		-		201		149		-		149
Total Revenues for Reportable Segments	$	13,656	$	80	$	13,736	$	10,284	$	-	$	10,284	$	9,700	$	-	$	9,700
Other (c)		781		(80)		701		163		-		163		325		-		325
Total Generation Consolidated Operating Revenues	$	14,437	$	0	$	14,437	$	10,447	$	-	$	10,447	$	10,025	$	-	$	10,025

Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation

Generation total revenues net of purchased power and fuel expense:
	2012						2011						2010
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	3,477	$	(44)	$	3,433	$	3,350	$	-	$	3,350	$	2,501	$	-	$	2,501
Midwest		2,974		24		2,998		3,547		-		3,547		4,081		-		4,081
New England		151		45		196		9		-		9		11		-		11
New York		101		(25)		76		0		-		0		0		-		0
ERCOT		403		2		405		84		-		84		(66)		-		(66)
Other Regions (b)		53		78		131		(14)		-		(14)		(65)		-		(65)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	7,159	$	80	$	7,239	$	6,976	$	-	$	6,976	$	6,462	$	-	$	6,462
Other (c)		217		(80)		137		(118)		-		(118)		100		-		100
Total Generation Revenues net of purchased power and fuel expense	$	7,376	$	0	$	7,376	$	6,858	$	-	$	6,858	$	6,562	$	-	$	6,562

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

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

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Income Loss From Equity Method Investments [Text Block]

		For the Period March 12,
		through December 31,
	2012
Equity investment income	$	83
Amortization of basis difference in CENG		(182)
Total equity in earnings (losses) - CENG	$	(99)

Schedule Of Equity Method Investment Summarized Financial Information [Text Block]


	Income/(Expense)			Accounts
	For the Period		Income	Receivable/
	March 12 through		Statement	(Accounts Payable)
Agreement	December 31, 2012		Classification	At December 31, 2012
PPA	$	(793)	Purchased power and fuel	$	(83)
PSAA		3	Operating revenues		-
SSA		42	Operating revenues		5

		For the Years Ended
		December 31,
		2012		2011		2010
Operating revenues from affiliates:
	PECO (a)	$	6	$	9	$	6
	CENG (b)		42		0		0

	Total operating revenues from affiliates	$	48	$	9	$	6

Fuel and purchased power from related parties:
	CENG (c)	$	793	$	0	$	0
	Keystone Fuels, LLC		61		68		74
	Conemaugh Fuels, LLC		68		69		70

	Total fuel purchases from related parties	$	922	$	137	$	144

Charitable contribution to Exelon Foundation(d)		$	7	$	0	$	10

Interest expense to affiliates, net:
	ComEd Financing III	$	13	$	13	$	13
	PECO Trust III		6		6		6
	PECO Trust IV		6		6		6

	Total interest expense to affiliates, net	$	25	$	25	$	25

(Loss) gain in equity method investments:
	CENG equity investment income	$	73	$	0		0
	Amortization of basis difference in CENG (e)		(172)		0		0
	Other		8		(1)		0

	Total loss in equity method investments	$	(91)	$	(1)	$	0

		December 31,
		2012		2011
Investments in affiliates:
	ComEd Financing III	$	6	$	6
	PECO Energy Capital Corporation		4		4
	PECO Trust IV		4		5
	BGE Capital Trust II		8		0


	Total investments in affiliates	$	22	$	15

Receivables from affiliates (current):
	CENG (b)	$	16	$	0

Payables to affiliates (current):
	CENG (c)	$	83	$	0
	ComEd Financing III		4		4
	PECO Trust III		1		1

	Total payables to affiliates (current)	$	88	$	5

Long-term debt to BondCo and other financing trusts (including due within one year):
	ComEd Financing III	$	206	$	206
	PECO Trust III		81		81
	PECO Trust IV		103		103
	BGE Capital Trust II		258		0

	Total long-term debt due to financing trusts	$	648	$	390

Exelon Generation Co L L C [Member]

		For the Years Ended
		December 31,
		2012		2011		2010
Operating revenues from affiliates:
	ComEd (a)	$	795	$	653	$	1,010
	PECO (b)		543		508		2,092
	BGE (c)		322		0		0
	CENG (d)		42		0		0

	Total operating revenues from affiliates	$	1,702	$	1,161	$	3,102

Fuel and purchased power from related parties:
	PECO	$	0	$	1	$	1
	BGE		8		0		0
	CENG (e)		793		0		0
	Keystone Fuels, LLC		61		68		74
	Conemaugh Fuels, LLC		68		69		70

	Total fuel purchases from related parties	$	930	$	138	$	145

Operating and maintenance from affiliates:
	ComEd (f)	$	2	$	2	$	2
	PECO (f)		3		5		4
	BSC (g)		625		314		285

	Total operating and maintenance from affiliates	$	630	$	321	$	291

(Loss) gain in equity method investments
	CENG equity investment income		73		0		0
	Amortization of basis difference in CENG (h)		(172)		0		0
	Qualifying facilities and domestic power projects		8		(1)		0

	Total loss in equity method investments		(91)	$	(1)	$	0

Cash distribution paid to member		$	1,626	$	172	$	1,508

Contribution from member		$	48	$	30	$	62

(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information.

(i) Represents the fair value of Generation's five-year financial swap contract with ComEd.

(k) In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

		December 31,
		2012		2011
Mark-to-market derivative assets with affiliates (current):
	ComEd (i)	$	226	$	503

Receivables from affiliates (current):
	ComEd (a)(j)	$	54	$	70
	PECO (b)		56		39
	BGE (c)		31		0

	Total receivables from affiliates (current)	$	141	$	109

Receivable from affiliate (noncurrent)
	Exelon	$	1	$	1

Mark-to-market derivative assets with affiliates (noncurrent):
	ComEd (i)	$	0	$	191

Payables to affiliates (current):
	CENG (e)	$	83	$	0
	Exelon (k)		33		7
	BSC (g)		77		51

	Total payables to affiliates (current)	$	193	$	58

Payables to affiliates (noncurrent):
	ComEd (l)	$	2,037	$	1,857
	PECO (l)		360		365

	Total payables to affiliates (noncurrent)	$	2,397	$	2,222

(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information.

(i) Represents the fair value of Generation's five-year financial swap contract with ComEd.

(k) In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

Commonwealth Edison Co [Member]

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates
	Generation	$	2	$	2	$	2

Purchased power from affiliate
	Generation (a)	$	789	$	653	$	1,010

Operating and maintenance from affiliate
	BSC (b)	$	163	$	158	$	152

Interest expense to affiliates, net:
	Exelon	$	0	$	2	$	0
	ComEd Financing III		13		13		13

	Total interest expense to affiliates, net	$	13	$	15	$	13

Capitalized costs
	BSC (b)	$	92	$	85	$	84

Cash dividends paid to parent		$	105	$	300	$	310

Contribution from parent		$	11	$	11	$	2

		December 31,
		2012			2011
Prepaid voluntary employee beneficiary association trust (c)		$	10	$	12

Investment in affiliate
	ComEd Financing III	$	6	$	6

Receivable from affiliates (noncurrent):
	Generation (d)	$	2,037	$	1,857
	Other		2		3

	Total receivable from affiliates (noncurrent)	$	2,039	$	1,860

Payables to affiliates (current):
	Generation (a)(e)	$	54	$	70
	BSC (b)		35		35
	ComEd Financing III		4		4
	Other		4		2

	Total payables to affiliates (current)	$	97	$	111

Mark-to-market derivative liability with affiliate (current)
	Generation (f)	$	226	$	503

Mark-to-market derivative liability with affiliate (noncurrent)
	Generation (f)	$	0	$	191

Long-term debt to ComEd financing trust
	ComEd Financing III	$	206	$	206

____________________

(f) To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation.

PECO Energy Co [Member]

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates:
	Generation (a)	$	3	$	5	$	5

Purchased power from affiliate
	Generation (b)	$	533	$	495	$	2,085

Operating and maintenance from affiliates:
	BSC (c)	$	107	$	92	$	89
	Generation		4		4		0

	Total operating and maintenance from affiliates	$	111	$	96	$	89

Interest expense to affiliates, net:
	PECO Trust III	$	6	$	6	$	6
	PECO Trust IV		6		6		6

	Total interest expense to affiliates, net	$	12	$	12	$	12

Loss in equity method investments

Capitalized costs
	BSC (c)	$	54	$	60	$	40

Cash dividends paid to parent		$	343	$	348	$	224

Repayment of receivable from parent		$	0	$	0	$	180

Contribution from parent		$	9	$	18	$	43

________

(a) PECO provides energy to Generation for Generation's own use.

		December 31,
		2012		2011
Prepaid voluntary employee beneficiary association trust (d)		$	2	$	3

Investments in affiliates:
	PECO Energy Capital Corporation	$	4	$	4
	PECO Trust IV		4		4

	Total investments in affiliates	$	8	$	8

Receivable from affiliate (noncurrent):
	Generation (e)	$	360	$	365

Mark-to-market derivative liability with affiliate (current):

Payables to affiliates (current):
	Generation (b)	$	56	$	39
	BSC (c)		18		21
	Exelon		1		1
	PECO Trust III		1		1

	Total payables to affiliates (current)	$	76	$	62

Long-term debt to financing trusts (including amounts due within one year):
	PECO Trust III	$	81	$	81
	PECO Trust IV		103		103

	Total long-term debt to financing trusts	$	184	$	184

(a) PECO provides energy to Generation for Generation's own use.

Baltimore Gas and Electric Company [Member]

		For the Years Ended
		December 31,

		2012		2011		2010
Operating revenues from affiliates:
	Generation (a)	$	10	$	8	$	7

Purchased power from affiliate
	Generation (b)	$	396	$	348	$	428

Operating and maintenance from affiliates:
	BSC (c)	$	106	$	150	$	126

Capitalized costs
	BSC (c)	$	21	$	29	$	49

Cash dividends paid to parent		$	0	$	(85)	$	0

Contribution from parent		$	66	$	0	$	0

		December 31,
		2012		2011

Investments in affiliates:
	BGE Capital Trust II	$	8	$	8

Payables to affiliates (current):
	Generation (b)	$	31	$	41
	BSC (c)		12		-
	Exelon (d)		17		-
	ComEd		3		-
	PECO		2		-

	Total payables to affiliates (current)	$	65	$	41

Long-term debt to BGE financing trust
	BGE Capital Trust II	$	258	$	258

Quarterly Data (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data [Line Items]

Quarterly Financial Information Table [Text Block]

									Net Income
									on Common
	Operating Revenues				Operating Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	4,686	$	4,956	$	359	$	1,202	$	200	$	668
June 30		5,954		4,496		714		1,034		286		620
September 30		6,565		5,254		603		1,181		296		601
December 31		6,284		4,357		704		1,062		378		606

Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share [Text Block]

	Average Basic Shares
	Outstanding				Net Income
	(in millions)				per Basic Share
	2012		2011		2012		2011
Quarter ended:
March 31		705		662	$	0.28	$	1.01
June 30		853		663		0.34		0.93
September 30		854		663		0.35		0.91
December 31		854		664		0.44		0.91

	Average Diluted Shares
	Outstanding				Net Income
	(in millions)				per Diluted Share
	2012		2011		2012		2011
Quarter ended:
March 31		707		664	$	0.28	$	1.01
June 30		856		664		0.33		0.93
September 30		857		665		0.35		0.90
December 31		857		666		0.44		0.91

Per Share Information [Text Block]

	2012								2011

	Fourth		Third		Second		First		Fourth			Third		Second		First
	Quarter		Quarter		Quarter		Quarter		Quarter			Quarter		Quarter		Quarter

High price	$	37.50	$	39.82	$	39.37	$	43.70	$	45.45		$	45.27	$	42.89	$	43.58
Low price		28.40		34.54		36.27		38.31		39.93			39.51		39.53		39.06
Close		29.74		35.58		37.62		39.21		43.37			42.61		42.84		41.24
Dividends		0.525		0.525		0.525		0.525		0.525	(a)		0.525		0.525		0.525

Exelon Generation Co L L C [Member]

Quarterly Financial Data [Line Items]

Quarterly Financial Information Table [Text Block]

									Net Income
									on Membership
	Operating Revenues				Operating Income				Interest
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	2,739	$	2,643	$	272	$	801	$	168	$	495
June 30		3,753		2,455		384		647		166		443
September 30		4,017		2,821		174		754		91		386
December 31		3,928		2,528		290		673		137		447

Commonwealth Edison Co [Member]

Quarterly Financial Data [Line Items]

Quarterly Financial Information Table [Text Block]

	Operating Revenues				Operating Income				Net Income
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	1,388	$	1,466	$	226	$	200	$	87	$	69
June 30		1,281		1,444		142		254		42		114
September 30		1,484		1,784		218		243		90		112
December 31		1,290		1,362		300		285		160		121

PECO Energy Co [Member]

Quarterly Financial Data [Line Items]

Quarterly Financial Information Table [Text Block]

									Net Income
									on Common
	Operating Revenues				Operating Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	875	$	1,153	$	177	$	210	$	96	$	125
June 30		715		842		151		161		79		82
September 30		806		946		178		153		122		104
December 31		790		778		117		131		79		73

Baltimore Gas and Electric Company [Member]

Quarterly Financial Data [Line Items]

Quarterly Financial Information Table [Text Block]

									Net (Loss) Income
					Operating				on Common
	Operating Revenues				(Loss) Income				Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	696	$	976	$	(11)	$	153	$	(33)	$	78
June 30		616		674		52		54		13		13
September 30		720		745		30		23		(4)		(2)
December 31		703		673		61		84		15		34

Significant Accounting Policies (Details) - USD ($)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Capitalized Interest And AFUDC [Line Items]

Total interest incurred

^[1]

$ 1,003,000,000

$ 783,000,000

$ 861,000,000

Capitalized interest

67,000,000

49,000,000

38,000,000

Credits to AFUDC debt and equity

25,000,000

16,000,000

Capitalized Software [Line Items]

Net unamortized software costs

499,000,000

280,000,000

Amortization of capitalized software costs

208,000,000

122,000,000

104,000,000

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Operating and maintenance

7,961,000,000

5,184,000,000

4,600,000,000

Interest Expense

$ 903,000,000

701,000,000

792,000,000

Consolidation Percentages Detail Tagging [Abstract]

Percentage ownership of consolidated subsidiaries

100.00%

Exelon Percentage ownership of Exelon SHC, LLC

1.00%

Generation's percentage ownership in transmission company

12.50%

Percentage ownership of ComEd's common stock

99.00%

Percentage ownership of common stock

100.00%

Third-party monetary interest in subsidiaries

$ 1,000,000

Third-party percentage interest in subsidiaries

12.50%

Minimum voting interest needed for a controlling financial interest

50.00%

New Site Development Costs [Abstract]

Capitalized development costs

$ 1,300,000

376,000,000

Development costs expensed

$ 4,200,000

2,000,000

6,000,000

Minimum [Member]

Consolidation Percentages Detail Tagging [Abstract]

Minimum voting interest needed for a controlling financial interest

20.00%

Maximum [Member]

Consolidation Percentages Detail Tagging [Abstract]

Minimum voting interest needed for a controlling financial interest

50.00%

Exelon Generation Co L L C [Member]

Capitalized Interest And AFUDC [Line Items]

Total interest incurred

^[1]

$ 368,000,000

219,000,000

191,000,000

Capitalized interest

67,000,000

49,000,000

38,000,000

Capitalized Software [Line Items]

Net unamortized software costs

143,000,000

82,000,000

Amortization of capitalized software costs

81,000,000

41,000,000

33,000,000

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Operating and maintenance

4,398,000,000

2,827,000,000

2,521,000,000

Interest Expense

$ 301,000,000

170,000,000

153,000,000

Consolidation Percentages Detail Tagging [Abstract]

Percentage ownership of consolidated subsidiaries

100.00%

Generation's percentage ownership in transmission company

99.00%

Ownership Interest Upper Bound

99.00%

Ownership Interest Lower Bound

94.00%

Nuclear Fuel [Abstract]

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

$ 0.001

Commonwealth Edison Co [Member]

Capitalized Interest And AFUDC [Line Items]

Total interest incurred

^[1]

310,000,000

349,000,000

388,000,000

Credits to AFUDC debt and equity

9,000,000

12,000,000

5,000,000

Capitalized Software [Line Items]

Net unamortized software costs

105,000,000

120,000,000

Amortization of capitalized software costs

56,000,000

50,000,000

41,000,000

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Electrical transmission and distribution revenue

5,441,000,000

6,054,000,000

6,202,000,000

Operating and maintenance

1,182,000,000

1,031,000,000

917,000,000

Interest Expense

$ 294,000,000

330,000,000

373,000,000

Consolidation Percentages Detail Tagging [Abstract]

Percentage ownership of consolidated subsidiaries

100.00%

Generation's percentage ownership in transmission company

75.00%

Third-party monetary interest in subsidiaries

$ 1,000,000

Third-party percentage interest in subsidiaries

25.00%

PECO Energy Co [Member]

Capitalized Interest And AFUDC [Line Items]

Total interest incurred

^[1]

$ 125,000,000

138,000,000

197,000,000

Credits to AFUDC debt and equity

6,000,000

13,000,000

11,000,000

Capitalized Software [Line Items]

Net unamortized software costs

63,000,000

67,000,000

Amortization of capitalized software costs

30,000,000

25,000,000

19,000,000

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Operating and maintenance

698,000,000

644,000,000

Interest Expense

111,000,000

122,000,000

181,000,000

Baltimore Gas and Electric Company [Member]

Capitalized Interest And AFUDC [Line Items]

Total interest incurred

^[1]

149,000,000

136,000,000

137,000,000

Credits to AFUDC debt and equity

15,000,000

22,000,000

16,000,000

Capitalized Software [Line Items]

Net unamortized software costs

157,000,000

62,000,000

Amortization of capitalized software costs

32,000,000

25,000,000

26,000,000

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Operating and maintenance

622,000,000

530,000,000

469,000,000

Interest Expense

144,000,000

$ 129,000,000

$ 131,000,000

Baltimore Gas and Electric Company [Member] | Restatement Adjustment [Member]

Error Corrections And Prior Period Adjustments Restatement [Line Items]

Electrical transmission and distribution revenue

2,000,000

Operating and maintenance

3,000,000

Interest Expense

$ 5,000,000

[1]

Basis of Presentation (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Current assets

$ 550,000

^[1]

$ 15,000

Noncurrent assets

1,802,000

^[1]

784,000

Total Assets

2,352,000

^[1]

799,000

Current liabilities

685,000

^[1]

181,000

Noncurrent liabilities

837,000

^[1]

77,000

Total Liabilities

1,522,000

^[1]

258,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Total assets

^[2]

740,000

Total liabilities

^[2]

333,000

Our ownership interest

^[2]

97,000

Other ownership interests

^[2]

310,000

Letter of Credit [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Investments [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

77,000

Payment Guarantee [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Exelon Generation Co L L C [Member]

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Current assets

519,000

15,000

Noncurrent assets

1,762,000

784,000

Total Assets

2,281,000

799,000

Current liabilities

613,000

181,000

Noncurrent liabilities

532,000

77,000

Total Liabilities

$ 1,145,000

258,000

Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member]

Consolidated Variable Interest Entity [Abstract]

Ownership percentage, consolidated variable interest entity (as a percent)

100.00%

Baltimore Gas and Electric Company [Member]

Consolidated Variable Interest Entity [Abstract]

Remittance of payments received from customers for rate stabilization to BondCo.

$ 85,000

92,000

$ 90,000

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Current assets

^[3]

30,000

Noncurrent assets

^[3]

Total Assets

^[3]

30,000

Current liabilities

^[3]

71,000

69,000

Noncurrent liabilities

^[3]

265,000

332,000

Total Liabilities

^[3]

$ 336,000

$ 401,000

[1]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[2]	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.
[3]	Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

Variable Interest Entities (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

Projects

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Consolidated Variable Interest Entities Disclosure [Abstract]

Current assets

$ 550,000

^[1]

$ 15,000

Noncurrent assets

1,802,000

^[1]

784,000

Total Assets

2,352,000

^[1]

799,000

Current liabilities

685,000

^[1]

181,000

Noncurrent liabilities

837,000

^[1]

77,000

Total Liabilities

1,522,000

^[1]

258,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Total assets

^[2]

740,000

Total liabilities

^[2]

333,000

Our ownership interest

^[2]

97,000

Other ownership interests

^[2]

310,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract]

Gross pledged assets

614,000

734,000

Pledged assets liabilities offset

564,000

691,000

Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Total assets

^[2]

386,000

Total liabilities

^[2]

219,000

Our ownership interest

^[2]

Other ownership interests

^[2]

167,000

Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Total assets

^[2]

354,000

Total liabilities

^[2]

114,000

Our ownership interest

^[2]

97,000

Other ownership interests

^[2]

143,000

Letter of Credit [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Letter of Credit [Member] | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Letter of Credit [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

Investments [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

77,000

Investments [Member] | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

Investments [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

77,000

Contract Intangible Asset [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

8,000

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

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

8,000

Contract Intangible Asset [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

Payment Guarantee [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Payment Guarantee [Member] | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

Payment Guarantee [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other ownership interests

5,000

Net assets pledged for Zion Station decommissioning

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Our maximum exposure to loss

^[3]

50,000

43,000

Net assets pledged for Zion Station decommissioning | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Our maximum exposure to loss

^[3]

50,000

43,000

Net assets pledged for Zion Station decommissioning | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Our maximum exposure to loss

^[3]

Exelon Generation Co L L C [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Current assets

519,000

15,000

Noncurrent assets

1,762,000

784,000

Total Assets

2,281,000

799,000

Current liabilities

613,000

181,000

Noncurrent liabilities

532,000

77,000

Total Liabilities

$ 1,145,000

258,000

Projects with significant economic power | Projects

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract]

Gross pledged assets

$ 614,000

734,000

Pledged assets liabilities offset

$ 564,000

691,000

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

Consolidated Variable Interest Entities Disclosure [Abstract]

Minority Interest Ownership Percentage By Noncontrolling Owners

1.00%

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

Consolidated Variable Interest Entities Disclosure [Abstract]

Minority Interest Ownership Percentage By Noncontrolling Owners

6.00%

Exelon Generation Co L L C [Member] | Retail Gas Customer Supply Operation [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Ownership percentage, consolidated variable interest entity (as a percent)

100.00%

Parental guarantee provided

$ 75,000

Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Ownership percentage, consolidated variable interest entity (as a percent)

100.00%

Business Acquisitions, Megawatts Acquired | MW

230

Aggregate amount of debt with third parties

$ 220,000

Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Ownership percentage, consolidated variable interest entity (as a percent)

100.00%

Projects with significant economic power | Projects

Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member] | Minimum [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Minority Interest Ownership Percentage By Noncontrolling Owners

99.00%

Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member] | Maximum [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Minority Interest Ownership Percentage By Noncontrolling Owners

94.00%

PECO Energy Co [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract]

Amount of PECO's stranded costs authorized to be recovered by the PAPUC

$ 5,000,000

Baltimore Gas and Electric Company [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Current assets

^[4]

30,000

Noncurrent assets

^[4]

Total Assets

^[4]

30,000

Current liabilities

^[4]

71,000

69,000

Noncurrent liabilities

^[4]

265,000

332,000

Total Liabilities

^[4]

336,000

401,000

Remittance of payments received from customers for rate stabilization to BondCo.

$ 85,000

$ 92,000

$ 90,000

[1]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[2]	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.
[3]	These items represent amounts on Generation’s and Exelon’s balance sheet related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $614 million and $734 million as of December 31, 2012 and December 31, 2011, respectively; offset by payables to ZionSolutions LLC of $564 million and $691 million as of December 31, 2012 and December 31, 2011, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 – Asset Retirement Obligations for further discussion.
[4]	Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

Regulatory Matters (Details)
$ in Thousands

1 Months Ended

9 Months Ended

12 Months Ended

Jun. 01, 2013

USD ($)

Jul. 27, 2012

USD ($)

Sep. 30, 2008

USD ($)

Sep. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

SmartMeters

AlternativeEnergyCredits

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Dec. 16, 2010

USD ($)

Operating And Maintenance For Regulatory Required Programs [Line Items]

Total operating and maintenance for regulatory required programs

Purchase Of Receivables [Abstract]

POR gross receivables

^[1]

191,000

68,000

POR Allowance for uncollectible accounts

^[2]

(21,000)

(5,000)

POR net receivables

170,000

63,000

Rate Relief Costs [Line Items]

Credits to ComEd customers

^[3]

15,000

Total incurred costs

15,000

Illinois Settlement Agreement [Abstract]

Overall rate relief contribution

$ 1,000,000

Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract]

Increase in electric delivery service revenue requirement resulting from regulatory order in rate case

$ 274,000

Illinois Procurement Proceedings [Abstract]

Near zero emissions coal-fueled generation plant | MW

166

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Pension and other postretirement benefit regulatory asset held at parent company

$ 3,977,000

Amortization of rate stabilization deferral

57,000

Recovered portion of regulatory assets

$ 129,000

63,000

931,000

Ownership of Salem Units

99.00%

Regulatory Asset [Line Items]

Noncurrent regulatory assets

$ 6,497,000

4,518,000

Current regulatory assets

759,000

390,000

Regulatory Liabilities [Line Items]

Regulatory Liability Current

321,000

197,000

Noncurrent regulatory liabilities

3,981,000

3,627,000

Regional Transmission Expansion Plan

PJM Transmission Rate Design And Operating Agreements Abstract

Total construction commitments

(525,000)

Construction commitments due in next twelve months

(175,000)

Construction commitments due in second year

(86,000)

Construction commitments due in third year

(135,000)

Construction commitments due in fourth year

(128,000)

Construction commitments due in five year

(1,000)

Nuclear Decommissioning [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

2,397,000

2,222,000

Removal Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

97,000

61,000

Noncurrent regulatory liabilities

1,406,000

1,185,000

Energy Efficiency Demand Response Programs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

131,000

49,000

Noncurrent regulatory liabilities

69,000

Electric Transmission And Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

20,000

19,000

Noncurrent regulatory liabilities

132,000

151,000

Over Recovered Uncollectible Accounts Expense [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

6,000

15,000

Noncurrent regulatory liabilities

Over Recovered Energy And Transmission Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

54,000

42,000

Noncurrent regulatory liabilities

Over-Recovered Universal Service Fund Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

3,000

Noncurrent regulatory liabilities

Over-Recovered AEPS Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

2,000

8,000

Noncurrent regulatory liabilities

Regulatory Liabilities Other [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Gas Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

8,000

Noncurrent regulatory liabilities

46,000

Exelon Generation Co L L C [Member]

Rate Relief Costs [Line Items]

Credits to ComEd customers

^[3]

14,000

Credits to other Illinois utilities' customers

^[3]

7,000

Total incurred costs

21,000

Illinois Settlement Agreement [Abstract]

Overall rate relief contribution

747,000

Rate relief to ComEd customers

435,000

Rate relief to other Illinois Utilities

308,000

Contribution to IPA

5,000

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Recovered portion of regulatory assets

$ 0

Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Salem [Member]

License Renewals [Abstract]

Ownership interest

42.59%

Commonwealth Edison Co [Member]

Purchase Of Receivables [Abstract]

POR gross receivables

^[1]

$ 55,000

16,000

POR Allowance for uncollectible accounts

^[2]

(9,000)

POR net receivables

46,000

16,000

Rate Relief Costs [Line Items]

Credits to ComEd customers

^[3]

1,000

Total incurred costs

1,000

Energy Infrastructure Modernization Act [Abstract]

Additional investment to modernize system and implement smart grid technology.

2,600

Annual contribution to fund customer assistance programs

10,000

Contribution to a science and technology innovation trust

15,000

Subsequent annual contributions to the trust

$ 4,000

Current length of state legislation enacted

10 years

Planned capital spend by a utility under state enacted legislation

$ 233,000

Annual revenue requirement reduction

168,000

Annual revenue requirement reduction incremental to proposal

110,000

Annual revenue requirement incremental reduction attributable to alternative recovery

50,000

Annual revenue requirement incremental reduction attributable to pensions

35,000

Annual revenue requirement incremental reduction attributable to incentives

10,000

Annual revenue requirement incremental reduction attributable to other adjustments

15,000

Regulatory asset reduction due to final order

100,000

Over or Under recovered distribution service costs

125,000

Under recovered distribution service costs related to one time events

84,000

Deferral of AMI plan

50,000

Deferral of additional capital investment

15,000

Regulatory asset for the accelerated depreciation of non-AMI meters

7,000

Increased revenue requirement

73,000

Expected revenue adjustment in subsequent quarter

135,000

Expected revenue adjustment for prior year

75,000

Expected revenue adjustment for current year

60,000

Regulatory assets due to deferred storm costs

58,000

Regulatory assets due to merger and integration-related costs

26,000

Other regulatory assets due to merger and integration-related costs

$ 5,000

Illinois Settlement Agreement [Abstract]

Rate relief to ComEd customers

64,000

Annual energy savings requirement

0.20%

Demand response peak demand reduction

2.00%

Renewable energy procurement

2.00%

Distribution Rate Case [Abstract]

Requested increase in electric revenues

396,000

Adjustment to Requested increase in electric revenues

343,000

Recovery request for Operating and Maintenance expenses of AMI Pilot Program

$ 40,000

Requested rate of return on common equity

11.50%

Rate of return on common equity electric distribution

10.30%

10.50%

Intervenor potential refund submitted in testimony

$ 37,000

Increase in electric delivery service revenue resulting from rate case settlement

$ 143,000

ComEd's proposed increase to net distribution revenue requirement related to uncollectable account expense

22,000

Utility Consolidated Billing and Purchase of Receivables [Abstract]

Purchased AR associated with PORCB

55,000

Illinois Legislation for Recovery of Uncollectible Accounts [Abstract]

Under-collected uncollectible accounts regulatory asset

70,000

One-time operating and maintenance expense charge

10,000

Annual Transmission Formula Rate Update [Abstract]

Gross transmission revenue requirement

450,000

438,000

Transmission revenue true up

5,000

16,000

Net transmission revenue requirement

$ 445,000

422,000

Advanced metering infrastructure pilot program [Abstract]

Collections Under Rider Amp

$ 24,000

Authorized Return On Rate Base [Abstract]

Weighted Average Debt And Equity Return

8.91%

9.10%

Rate Of Return On Common Equity

11.50%

Common Equity Component Cap

55.00%

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Recovered portion of regulatory assets

$ 80,000

$ 52,000

43,000

Regulatory Asset [Line Items]

Noncurrent regulatory assets

666,000

699,000

Current regulatory assets

388,000

657,000

Regulatory Liabilities [Line Items]

Regulatory Liability Current

130,000

137,000

Noncurrent regulatory liabilities

$ 3,229,000

3,042,000

Commonwealth Edison Co [Member] | Minimum [Member]

Energy Efficiency Program [Abstract]

Renewable energy resources that will cumulatively increase

10.00%

Commonwealth Edison Co [Member] | Maximum [Member]

Energy Efficiency Program [Abstract]

Renewable energy resources that will cumulatively increase

25.00%

Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

$ 0

Noncurrent regulatory liabilities

2,037,000

1,857,000

Commonwealth Edison Co [Member] | Removal Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

75,000

61,000

Noncurrent regulatory liabilities

1,192,000

1,185,000

Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

43,000

49,000

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Over Recovered Uncollectible Accounts Expense [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

6,000

15,000

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

6,000

12,000

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Over-Recovered AEPS Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Regulatory Liabilities Other [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Commonwealth Edison Co [Member] | Gas Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

PECO Energy Co [Member]

Purchase Of Receivables [Abstract]

POR gross receivables

^[1]

65,000

52,000

POR Allowance for uncollectible accounts

^[2]

(6,000)

(5,000)

POR net receivables

59,000

47,000

Distribution Rate Case [Abstract]

Increase in electric delivery service revenue resulting from rate case settlement

$ 225,000

Increase in gas delivery service revenue resulting from rate case settlement

$ 20,000

Electric Distribution Tax Repairs Refund

$ 171,000

Smart Meter and Smart Grid Investments [Abstract]

Estimated number of smart meters to be installed | SmartMeters

600,000

Expected number of smart meters to be deployed during the first phase of Smart Meter Installment Plan

1,600

Revised spend on its Smart Meter Procurement and Installation Plan

$ 595,000

Spend on smart grid investments

120,000

Smart meter spend to date

241,000

Smart grid infrastructure spend to date

100,000

Total smart grid and smart meter investment grant amount

200,000

Smart meter investment grant awarded

140,000

Smart grid investment grant awarded

60,000

Reimbursements received from the DOE

144,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

17,000

Regulatory assets for original smart meters purchased

17,000

Carrying value of originally installed Smart Meters, net of reimbursements from DOE

19,000

Amount of reimbursements received from the DOE applied to the originally installed Smart Meters.

$ 16,000

Alternative Energy Portfolio Standards [Abstract]

Total alternative energy credits purchased annually | AlternativeEnergyCredits

452,000

Solar tier 1 alternative energy credits purchased annually | AlternativeEnergyCredits

8,000

Tier II AECs Purchased | AlternativeEnergyCredits

275,000

Natural Gas Distribution Rate Case [Abstract]

Gas Distribution Tax Repairs Refund

$ 54,000

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Over under recovered transmission costs

$ 1,000

9,000

Over under recovered electric supply costs

47,000

25,000

Over under recovered gas supply costs

1,000

5,000

Recovered portion of regulatory assets

10,000

11,000

^[4]

889,000

^[4]

Natural Gas Supplier Tariff [Abstract]

Natural gas supplier tariff total collateral

14,000

Regulatory Asset [Line Items]

Noncurrent regulatory assets

1,378,000

1,216,000

Current regulatory assets

32,000

39,000

Regulatory Liabilities [Line Items]

Regulatory Liability Current

169,000

60,000

Noncurrent regulatory liabilities

$ 538,000

585,000

PECO Energy Co [Member] | Minimum [Member]

Alternative Energy Portfolio Standards [Abstract]

Percentage Tier I alternative energy resources

3.50%

Percentage Tier II alternative energy resources

6.20%

PECO Energy Co [Member] | Maximum [Member]

Alternative Energy Portfolio Standards [Abstract]

Percentage Tier I alternative energy resources

8.00%

Percentage Tier II alternative energy resources

10.00%

PECO Energy Co [Member] | Regional Transmission Expansion Plan

PJM Transmission Rate Design And Operating Agreements Abstract

Total construction commitments

$ (140,000)

Construction commitments due in next twelve months

(28,000)

Construction commitments due in second year

(23,000)

Construction commitments due in third year

(26,000)

Construction commitments due in fourth year

(36,000)

Construction commitments due in five year

(27,000)

PECO Energy Co [Member] | Nuclear Decommissioning [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

360,000

365,000

PECO Energy Co [Member] | Removal Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

88,000

Noncurrent regulatory liabilities

69,000

PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

20,000

19,000

Noncurrent regulatory liabilities

132,000

151,000

PECO Energy Co [Member] | Over Recovered Uncollectible Accounts Expense [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

48,000

30,000

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

3,000

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Over-Recovered AEPS Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

2,000

8,000

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Regulatory Liabilities Other [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

8,000

Noncurrent regulatory liabilities

46,000

PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]

Illinois Settlement Agreement [Abstract]

Annual energy savings requirement

3.00%

Demand response peak demand reduction

4.50%

Energy Efficiency Program [Abstract]

Maximum civil penalty under Act 129

$ 20,000

Total approved amount under energy efficiency and conservation / demand plan

$ 328,000

Cumulative Consumption Reduction Targets

2.90%

Consumption reduction target (as a percentage) mandated by the Energy Efficiency Program - Phase II Implemtation Order for programs directed towards the Utility's low income sector.

4.50%

Consumption reduction targets for public sector under Act 129 Phase II Implementation Order

10.00%

Total approved amount under phase II of Act 129 as percent of total annual revenue

2.00%

Baltimore Gas and Electric Company [Member]

Purchase Of Receivables [Abstract]

POR gross receivables

^[1]

71,000

61,000

POR Allowance for uncollectible accounts

^[2]

(6,000)

(3,000)

POR net receivables

65,000

58,000

Energy Infrastructure Modernization Act [Abstract]

Other regulatory assets due to merger and integration-related costs

1,000

Distribution Rate Case [Abstract]

Requested increase in electric revenues

$ 131,000

Requested increase in gas revenues

$ 45,000

Requested rate of return on common equity

10.50%

Annual Transmission Formula Rate Update [Abstract]

Gross transmission revenue requirement

156,000

Transmission revenue true up

2,000

Net transmission revenue requirement

$ 158,000

$ 140,000

Smart Meter and Smart Grid Investments [Abstract]

Estimated number of smart meters to be installed | SmartMeters

2,000,000

Total smart grid and smart meter investment grant amount

$ 200,000

Reimbursements received from the DOE

142,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

15,000

Total Projected smart meter smart grid spend

$ 480,000

New Electric Generation [Abstract]

Megawatt capacity of new generating plant | MW

700

Authorized Return On Rate Base [Abstract]

Weighted Average Debt And Equity Return

8.43%

8.96%

Rate Of Return On Common Equity

11.30%

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Over under recovered electric supply costs

$ (9,000)

Over under recovered gas supply costs

(19,000)

Amortization of rate stabilization deferral

67,000

$ 57,000

62,000

Total cost of smart grid pilot program

11,000

Portion of electric generation-related regulatory asset representing income taxes recoverable that do not earn a regulated rate of return

$ 47,000

56,000

Rate cap for BGE residential electric customers from July 1, 2006 until May 31, 2007 (as a percent)

15.00%

Deferred expense related to electricity purchased for resale

$ 306,000

Recovered portion of regulatory assets

$ 53,000

50,000

$ 35,000

Equity Ratio Minimum After Dividend Payments

48.00%

Maryland Electric And Natural Gas Distribution Rate Cases [Abstract]

Deferral of total costs

$ 19,000

Deferral of storm costs

16,000

(16,000)

Regulatory Asset [Line Items]

Noncurrent regulatory assets

522,000

551,000

Current regulatory assets

185,000

175,000

Regulatory Liabilities [Line Items]

Regulatory Liability Current

22,000

19,000

Noncurrent regulatory liabilities

214,000

201,000

Baltimore Gas and Electric Company [Member] | Regional Transmission Expansion Plan

PJM Transmission Rate Design And Operating Agreements Abstract

Total construction commitments

(249,000)

Construction commitments due in next twelve months

(15,000)

Construction commitments due in second year

(53,000)

Construction commitments due in third year

(119,000)

Construction commitments due in fourth year

(55,000)

Construction commitments due in five year

(7,000)

Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Removal Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

22,000

18,000

Noncurrent regulatory liabilities

214,000

200,000

Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Over Recovered Uncollectible Accounts Expense [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Over-Recovered AEPS Costs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

Baltimore Gas and Electric Company [Member] | Regulatory Liabilities Other [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

1,000

Noncurrent regulatory liabilities

$ 1,000

Baltimore Gas and Electric Company [Member] | Gas Distribution Tax Repairs [Member]

Regulatory Liabilities [Line Items]

Regulatory Liability Current

Noncurrent regulatory liabilities

[1]	PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
[2]	For ComEd, 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.
[3]	Recorded as a reduction in operating revenues.
[4]	For PECO, primarily reflects CTC amortization.

Merger and Acquisitions (Details)
$ / shares in Units, SolarPanels in Thousands

3 Months Ended

9 Months Ended

12 Months Ended

Nov. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

Sep. 30, 2012

USD ($)

Jun. 30, 2012

USD ($)

Mar. 31, 2012

USD ($)

Dec. 31, 2011

USD ($)

Sep. 30, 2011

USD ($)

Jun. 30, 2011

USD ($)

Mar. 31, 2011

USD ($)

Sep. 30, 2011

USD ($)

Dec. 31, 2012

USD ($)

NumberOfHomes

SolarPanels

$ / shares

Dec. 31, 2011

USD ($)

$ / shares

Dec. 31, 2010

USD ($)

Apr. 05, 2012

USD ($)

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

$ 576,000,000

Finite lived intangible assets accumulated amortization

(132,000,000)

Finite lived intangible assets net

444,000,000

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

28,000,000

Future amortization expense in year two

29,000,000

Future mortizationExpense in year three

29,000,000

Future amortization expense in year four

29,000,000

Future amortization expense in year five

29,000,000

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Contingent consideration at fair value

$ (32,000,000)

Business Acquisition, Purchase Price Allocation [Abstract]

Business Acquisition, Purchase Price Allocation, Current Assets

4,936,000,000

Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment

9,342,000,000

Business Acquisition, Purchase Price Allocation, Intangible Assets, Contracts

3,218,000,000

Business Acquisition, Purchase Price Allocation, Intangible Assets, Relationships

457,000,000

Business Acquisition, Purchase Price Allocation, CENG Investment

1,942,000,000

Business Acquisition, Purchase Price Allocation, Pension Regulatory Asset

740,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Assets

2,265,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired

22,900,000,000

Business Acquisition, Purchase Price Allocation, Current Liabilities

3,408,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities

4,683,000,000

Business Acquisition, Purchase Price Allocation, Liability Contracts

1,722,000,000

Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt

5,632,000,000

Business Combination Acquisition Of Less Than 100 Percent Noncontrolling Interest Fair Value

90,000,000

Business Acquisition, Purchase Price Allocation, Liabilities Assumed

15,535,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net

7,365,000,000

Business Acquisition, Impact Of Merger [Abstract]

Revenues

6,284,000,000

$ 6,565,000,000

$ 5,954,000,000

$ 4,686,000,000

$ 4,357,000,000

$ 5,254,000,000

$ 4,496,000,000

$ 4,956,000,000

23,489,000,000

$ 19,063,000,000

18,644,000,000

Net income

378,000,000

296,000,000

286,000,000

200,000,000

606,000,000

601,000,000

620,000,000

668,000,000

1,171,000,000

2,499,000,000

2,563,000,000

Business Acquisition, Pro Forma Information [Abstract]

Business Acquisition, Pro Forma Revenue

26,700,000,000

30,712,000,000

^[1]

Business Acquisition, Pro Forma Net Income (Loss)

$ 2,092,000,000

$ 974,000,000

^[1]

Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares

$ 2.56

$ 1.15

^[1]

Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares

$ 2.55

$ 1.14

^[1]

Business Acquisition, Pro Forma Nonrecurring Cost

$ 236,000,000

Business Acquisition, Costs Recognized Post Merger [Abstract]

Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers

$ 113,500,000

Contribution for renewable energy, energy efficiency or related projects in Baltimore

2,000,000

BGE rate credit of $100 per residential customer

^[2]

113,000,000

Charitable contributions at $7 million per year for 10 years

$ 70,000,000

Length of years for charitable contributions at $7 million per year

10 years

State funding for offshore wind development projects

$ 32,000,000

Miscellaneous tax benefits

(2,000,000)

Total

328,500,000

Business Acquisition Charitable Contributions Per Year

$ 7,000,000

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Expected New Generation Development Time Frame

10 years

Business Acquisition, Divesture Sales Days

150 days

Business Acquisition, Divesture Sales Days Extension

30 days

Business Acquisition Potential Cash Payment

40,000,000

$ 40,000,000

Restructuring Reserve [Roll Forward]

Severance Charges

^[3]

124,000,000

Stock Compensation Expense

^[3]

7,000,000

Other Expense Charges

^[3]

7,000,000

Total Severance Benefits

^[3]

138,000,000

Payments

27,000,000

Restructuring Reserve, Period End

111,000,000

Minimum [Member]

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Construction Cost

$ 95,000,000

Business Acquisition, Construction Time Frame

1 year

Business Acquisition, Expected New Generation Mwh | MW

285

Maximum [Member]

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Construction Cost

$ 120,000,000

Business Acquisition, Construction Time Frame

2 years

Business Acquisition, Expected New Generation Mwh | MW

300

Severance [Member]

Restructuring Reserve [Roll Forward]

Severance Charges

^[4]

$ 124,000,000

One-time Termination Benefits [Member]

Restructuring Reserve [Roll Forward]

Restructuring Reserve, Period Expense

3,000,000

Stock Compensation Plan [Member]

Restructuring Reserve [Roll Forward]

Stock Compensation Expense

7,000,000

Other Severance Charges [Member]

Restructuring Reserve [Roll Forward]

Other Expense Charges

^[5]

7,000,000

Constellation Energy Group Acquisition [Member]

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

1,953,000,000

Finite lived intangible assets accumulated amortization

(1,017,000,000)

Finite lived intangible assets net

936,000,000

Amortization Of Contracts

1,098,000,000

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

437,000,000

Future amortization expense in year two

117,000,000

Future mortizationExpense in year three

62,000,000

Future amortization expense in year four

12,000,000

Future amortization expense in year five

21,000,000

Future amortization expense in year six and thereafter

287,000,000

Constellation Energy Group Acquisition [Member]

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Integration Related Costs

746,000,000

77,000,000

Business Acquisition, Regulatory Matters [Abstract]

Business Acquisition, Direct Investment With State And Local Governments Due To Settlement

1,000,000,000

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Development Of New Generation Cost

625,000,000

$ 625,000,000

Business Acquisition, Divesture Wattage | MW

2,648

Business Acquisition, Proceeds Assets Held For Sale

$ 371,000,000

Business Acquisition, Gain (Loss) On Sale Of Assets Held For Sale

278,000,000

Business Acquisition, Gain (Loss) On Sale Of Assets Held For Sale Update

$ 272,000,000

Wolf Hollow Acquisition [Member]

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Business Acquisition Cost Of Acquired Entity Cash Paid

305,000,000

Business Acquisition, Preexisting Relationship, Gain (Loss) Recognized

6,000,000

Total fair value of consideration recorded

311,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment

347,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory

5,000,000

Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital

(5,000,000)

Total net identifiable assets

347,000,000

Business Combination, Bargain Purchase [Abstract]

Business Combination, Bargain Purchase, Gain Recognized, Amount

36,000,000

Antelope Valley Solar Ranch One Acquisition [Member]

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Business Acquisition Cost Of Acquired Entity Cash Paid

75,000,000

Total fair value of consideration recorded

75,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment

15,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Intangibles

^[6]

190,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

^[7]

135,000,000

Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Other Assets And Liabilities

5,000,000

Total net identifiable assets

75,000,000

Exelon Wind Acquisition [Member]

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Business Acquisition Cost Of Acquired Entity Cash Paid

893,000,000

Escrow Deposit

32,000,000

Total fair value of consideration recorded

925,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment

700,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Intangibles

^[6]

224,000,000

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed, Non-Controlling Interest

(3,000,000)

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Asset Retirment Obligations

(13,000,000)

Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital

18,000,000

Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Other Assets And Liabilities

(1,000,000)

Total net identifiable assets

925,000,000

Exelon Generation Co L L C [Member]

Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]

Contingent consideration at fair value

(32,000,000)

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

DOE advances received

219,000,000

$ 219,000,000

$ 69,000,000

DOE loan guarantee

646,000,000

Business Acquisition, Purchase Price Allocation [Abstract]

Business Acquisition, Purchase Price Allocation, Current Assets

3,638,000,000

Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment

4,054,000,000

Business Acquisition, Purchase Price Allocation, Intangible Assets, Contracts

3,218,000,000

Business Acquisition, Purchase Price Allocation, Intangible Assets, Relationships

457,000,000

Business Acquisition, Purchase Price Allocation, CENG Investment

1,942,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Assets

1,266,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired

14,575,000,000

Business Acquisition, Purchase Price Allocation, Current Liabilities

2,804,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities

1,933,000,000

Business Acquisition, Purchase Price Allocation, Liability Contracts

1,512,000,000

Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt

2,972,000,000

Business Combination Acquisition Of Less Than 100 Percent Noncontrolling Interest Fair Value

90,000,000

Business Acquisition, Purchase Price Allocation, Liabilities Assumed

9,311,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net

5,264,000,000

Business Acquisition, Impact Of Merger [Abstract]

Revenues

3,928,000,000

4,017,000,000

3,753,000,000

2,739,000,000

2,528,000,000

2,821,000,000

2,455,000,000

2,643,000,000

14,437,000,000

10,447,000,000

10,025,000,000

Net income

137,000,000

91,000,000

166,000,000

168,000,000

447,000,000

386,000,000

443,000,000

495,000,000

558,000,000

1,771,000,000

$ 1,972,000,000

Business Acquisition, Pro Forma Information [Abstract]

Business Acquisition, Pro Forma Revenue

17,013,000,000

19,494,000,000

^[8]

Business Acquisition, Pro Forma Net Income (Loss)

1,205,000,000

324,000,000

^[8]

Business Acquisition, Pro Forma Nonrecurring Cost

203,000,000

Business Acquisition, Costs Recognized Post Merger [Abstract]

Charitable contributions at $7 million per year for 10 years

35,000,000

Total

35,000,000

Restructuring Reserve [Roll Forward]

Severance Charges

^[3]

80,000,000

Stock Compensation Expense

^[3]

4,000,000

Other Expense Charges

^[3]

4,000,000

Total Severance Benefits

^[3]

88,000,000

Payments

9,000,000

Restructuring Reserve, Intercompany Allocation

46,000,000

Restructuring Reserve, Period End

33,000,000

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

Restructuring Reserve [Roll Forward]

Severance Charges

^[4]

38,000,000

Exelon Generation Co L L C [Member] | One-time Termination Benefits [Member]

Restructuring Reserve [Roll Forward]

Restructuring Reserve, Period Expense

1,000,000

Exelon Generation Co L L C [Member] | Stock Compensation Plan [Member]

Restructuring Reserve [Roll Forward]

Stock Compensation Expense

2,000,000

Exelon Generation Co L L C [Member] | Other Severance Charges [Member]

Restructuring Reserve [Roll Forward]

Other Expense Charges

^[5]

2,000,000

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

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Integration Related Costs

340,000,000

$ 15,000,000

Exelon Generation Co L L C [Member] | Wolf Hollow Acquisition [Member]

Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]

Business Acquisitions, Megawatts Acquired | MW

720

Exelon Generation Co L L C [Member] | Antelope Valley Solar Ranch One Acquisition [Member]

Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]

Business Acquisitions, Megawatts Acquired | MW

230

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Expected Investment In Equity

701,000,000

DOE advances received

69,000,000

DOE loan guarantee

$ 646,000,000

Amount of solar panels | SolarPanels

3,800

Amount of homes powered by electricity generated | NumberOfHomes

75,000

Purchased Power agreement time

25 years

Footnotes To Business Combination Recognized Identifiable Assets Acquired Liabilities Assumed Net [Abstract]

First Solar Corporation Payable

87,000,000

135,000,000

$ 87,000,000

$ 135,000,000

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

Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]

Business Acquisitions, Megawatts Acquired | MW

735

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Contingent consideration potential cash payment

40,000,000

$ 40,000,000

Contingent consideration paid

$ 16,000,000

Acquisition of John Deere Renewables additional wind projects in advance stages of development capacity | MW

230

Probability of project to be constructed

100.00%

Contingent consideration recorded in operation and maintenance expense

$ 2,000,000

Contingent consideration recorded in current liabilities

10,000,000

Contingent consideration recorded in deferred credits

8,000,000

Commonwealth Edison Co [Member]

Business Acquisition, Impact Of Merger [Abstract]

Revenues

1,290,000,000

1,484,000,000

1,281,000,000

1,388,000,000

1,362,000,000

1,784,000,000

1,444,000,000

1,466,000,000

5,443,000,000

6,056,000,000

$ 6,204,000,000

Net income

160,000,000

90,000,000

42,000,000

87,000,000

121,000,000

112,000,000

114,000,000

69,000,000

379,000,000

416,000,000

337,000,000

Restructuring Reserve [Roll Forward]

Severance Charges

^[3],[9]

14,000,000

Stock Compensation Expense

^[3],[9]

1,000,000

Other Expense Charges

^[3],[9]

1,000,000

Total Severance Benefits

^[3],[9]

16,000,000

Payments

1,000,000

Restructuring Reserve, Intercompany Allocation

14,000,000

Restructuring Reserve, Period End

1,000,000

16,000,000

Commonwealth Edison Co [Member] | Severance [Member]

Restructuring Reserve [Roll Forward]

Severance Charges

^[4]

2,000,000

Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member]

Restructuring Reserve [Roll Forward]

Merger related regulatory asset

36,000,000

Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member]

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Integration Related Costs

5,000,000

PECO Energy Co [Member]

Business Acquisition, Impact Of Merger [Abstract]

Revenues

790,000,000

806,000,000

715,000,000

875,000,000

778,000,000

946,000,000

842,000,000

1,153,000,000

3,186,000,000

3,720,000,000

5,519,000,000

Net income

79,000,000

122,000,000

79,000,000

96,000,000

73,000,000

104,000,000

82,000,000

125,000,000

381,000,000

389,000,000

324,000,000

Restructuring Reserve [Roll Forward]

Severance Charges

^[3]

7,000,000

Total Severance Benefits

^[3]

7,000,000

Restructuring Reserve, Intercompany Allocation

7,000,000

PECO Energy Co [Member] | Constellation Energy Group Acquisition [Member]

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Integration Related Costs

17,000,000

2,000,000

Baltimore Gas and Electric Company [Member]

Business Acquisition, Impact Of Merger [Abstract]

Revenues

703,000,000

720,000,000

616,000,000

696,000,000

673,000,000

745,000,000

674,000,000

976,000,000

2,735,000,000

3,068,000,000

3,541,000,000

Revenues Impact

2,091,000,000

Net Income Loss Impact

(31,000,000)

Net income

15,000,000

$ (4,000,000)

$ 13,000,000

$ (33,000,000)

$ 34,000,000

$ (2,000,000)

$ 13,000,000

$ 78,000,000

4,000,000

$ 136,000,000

$ 147,000,000

Business Acquisition, Costs Recognized Post Merger [Abstract]

Business Acquisition, Regulatory Rate Credit Per Customer

100

BGE rate credit of $100 per residential customer

^[2]

113,000,000

Charitable contributions at $7 million per year for 10 years

28,000,000

Miscellaneous tax benefits

(2,000,000)

Total

139,000,000

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Equity Contribution

66,000,000

Restructuring Reserve [Roll Forward]

Severance Charges

^[3],[10]

17,000,000

Stock Compensation Expense

^[3],[10]

1,000,000

Other Expense Charges

^[3],[10]

1,000,000

Total Severance Benefits

^[3],[10]

19,000,000

Payments

1,000,000

Restructuring Reserve, Intercompany Allocation

7,000,000

Restructuring Reserve, Period End

11,000,000

19,000,000

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

Restructuring Reserve [Roll Forward]

Severance Charges

^[4]

11,000,000

Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member]

Restructuring Reserve [Roll Forward]

Other Expense Charges

^[5]

1,000,000

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member]

Restructuring Reserve [Roll Forward]

Merger related regulatory asset

22,000,000

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member]

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Integration Related Costs

$ 160,000,000

Customer Relationships [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

12 years 4 months 26 days

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

214,000,000

$ 214,000,000

Finite lived intangible assets accumulated amortization

(15,000,000)

Finite lived intangible assets net

199,000,000

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

19,000,000

Future amortization expense in year two

19,000,000

Future mortizationExpense in year three

19,000,000

Future amortization expense in year four

19,000,000

Future amortization expense in year five

19,000,000

Future amortization expense in year six and thereafter

$ 104,000,000

Trade Names [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

10 years

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

243,000,000

$ 243,000,000

Finite lived intangible assets accumulated amortization

(20,000,000)

Finite lived intangible assets net

223,000,000

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

24,000,000

Future amortization expense in year two

24,000,000

Future mortizationExpense in year three

24,000,000

Future amortization expense in year four

24,000,000

Future amortization expense in year five

24,000,000

Future amortization expense in year six and thereafter

103,000,000

Power Supply Contracts [Member]

Finite Lived Intangible Assets Net [Abstract]

Amortization of Regulatory Asset

116,000,000

$ 116,000,000

Power Supply Contracts [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

^[11]

1 year 6 months 3 days

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

^[11]

1,496,000,000

$ 1,496,000,000

Finite lived intangible assets accumulated amortization

^[11]

(982,000,000)

Finite lived intangible assets net

^[11]

514,000,000

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

^[11]

394,000,000

Future amortization expense in year two

^[11]

74,000,000

Future mortizationExpense in year three

^[11]

19,000,000

Future amortization expense in year four

^[11]

(31,000,000)

Future amortization expense in year five

^[11]

(22,000,000)

Future amortization expense in year six and thereafter

^[11]

$ 80,000,000

Constellation Energy Group Acquisition [Member] | Common Stock [Member]

Business Acquisition, Equity Interests Issued or Issuable [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

^[12]

187,450,000

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

^[12]

7,294,000,000

$ 7,294,000,000

Business Acquisition, Equity Interest Issued Or Issuable, Exchange Ratio | shares

0.930

Business Acquisition, Equity Interest Issued or Issuable, Stock Price

38.91

$ 38.91

Business Acquisition, Equity Interest Issued Or Issuable, Stock Withheld | shares

700,000

Constellation Energy Group Acquisition [Member] | Equity Awards [Member]

Business Acquisition, Equity Interests Issued or Issuable [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

^[13]

11,300,000

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

^[13]

$ 71,000,000

[1]	The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.
[2]	Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.
[3]	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
[4]	Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. Amounts also include one-time termination benefits of $3 million and $1 million for Exelon and Generation, respectively, which they began to recognize in the second quarter of 2012.
[5]	Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services.
[6]	See Note 8 - Intangible Assets for additional information.
[7]	Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a "seller financing" arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation's implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc.
[8]	The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.
[9]	ComEd established regulatory assets of $16 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
[10]	Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
[11]	(a) Includes the fair value of BGE's power and gas supply contracts for which an offsetting Exelon Corporate regulatory asset was also recorded.
[12]	The number of shares issued excludes 0.7 million shares of stock that are held in a custodian account specifically for the settlement of unvested share-based restricted stock awards. The related share value is excluded from the estimated fair value as these awards have not vested and, therefore, are not in the purchase price.
[13]	Includes vested Constellation stock options and restricted stock units converted at fair value to Exelon awards on March 12, 2012. The fair value of the stock options was determined using the Black-Scholes model.

Investment in Constellation Energy Nuclear Group, LLC (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Impact Of Transactions Under Agreements [Abstract]
Increase (Decrease) in earnings	$ 48,000	$ 9,000	$ 6,000
Amortization of energy contract assets and liabilities	$ 1,110,000
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest in CENG (as a percent)	1.00%
Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Purchase of nuclear output by EDF (as a percent)	49.99%
Impact Of Transactions Under Agreements [Abstract]
Increase (Decrease) in earnings	$ 1,702,000	$ 1,161,000	$ 3,102,000
Amortization of energy contract assets and liabilities	$ 1,110,000
Exelon Generation Co L L C [Member] \| CENG [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest in CENG (as a percent)	50.01%
Basis difference in investment in CENG	$ 204,000

Goodwill (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

Goodwill [Roll Forward]

Goodwill, beginning balance

$ 2,625,000

Goodwill Impairment Loss

Goodwill, ending balance

2,625,000

Goodwill Gross [Member]

Goodwill [Roll Forward]

Goodwill Impairment Loss

^[1]

Goodwill, ending balance

4,608,000

^[1]

Goodwill Accumulated Impairment Losses [Member]

Goodwill [Roll Forward]

Goodwill Impairment Loss

Goodwill, ending balance

1,983,000

Commonwealth Edison Co [Member]

Goodwill, Impaired [Abstract]

Annual revenue requirement reduction

168,000

Goodwill [Roll Forward]

Goodwill, beginning balance

2,625,000

Goodwill Impairment Loss

Goodwill, ending balance

2,625,000

Commonwealth Edison Co [Member] | Goodwill Gross [Member]

Goodwill [Roll Forward]

Goodwill, beginning balance

4,608,000

Goodwill Impairment Loss

^[1]

Goodwill, ending balance

4,608,000

^[1]

Commonwealth Edison Co [Member] | Goodwill Accumulated Impairment Losses [Member]

Goodwill [Roll Forward]

Goodwill, beginning balance

1,983,000

Goodwill Impairment Loss

Goodwill, ending balance

$ 1,983,000

[1]	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Loss recognized during the period that results from the write-down of goodwill after comparing the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. Goodwill is assessed at least annually for impairment.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13854-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13777-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 20
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 47
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Accounts Notes And Loans Receivable Net Current [Abstract]
Unbilled revenues	$ 1,418,000	$ 902,000
Allowance for uncollectible accounts	(293,000)	(199,000)
Accounts Receivable Additional Disclosures [Abstract]
Accounts receivable, pledged under accounts receivable agreement	225,000
Gross Accounts Receivable Pledged as Collateral	289,000	346,000
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables	18,000	21,000
Exelon Generation Co L L C [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Unbilled revenues	859,000	493,000
Allowance for uncollectible accounts	(84,000)	(29,000)
Commonwealth Edison Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Unbilled revenues	213,000	246,000
Allowance for uncollectible accounts	(70,000)	(78,000)
PECO Energy Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Unbilled revenues	164,000	163,000
Allowance for uncollectible accounts	(99,000)	(92,000)
Accounts Notes And Loans Receivable Net Current Footnotes [Abstract]
Current financing receivable allowance for credit losses	7,000	8,000
Accounts Receivable Additional Disclosures [Abstract]
Accounts receivable, pledged under accounts receivable agreement	225,000
Gross Accounts Receivable Pledged as Collateral	289,000	329,000
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(15,000)	(17,000)
PECO Energy Co [Member] \| Low Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(1,000)	(1,000)
PECO Energy Co [Member] \| Medium Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(3,000)	(3,000)
PECO Energy Co [Member] \| High Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(11,000)	(13,000)
Baltimore Gas and Electric Company [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Unbilled revenues	182,000	194,000
Allowance for uncollectible accounts	$ (40,000)	$ (37,000)

Property, Plant and Equipment (Details) - USD ($)

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Property Plant And Equipment [Line Items]

Total property, plant and equipment

$ 57,370,000,000

$ 43,529,000,000

Less: accumulated depreciation

^[1]

(12,184,000,000)

(10,959,000,000)

Property, plant and equipment, net

45,186,000,000

32,570,000,000

Property Plant And Equipment Footnotes [Abstract]

Nuclear fuel - work in progress

6,000,000

Buildings under capital lease

2,000,000

Original cost basis for buildings

53,000,000

Accumulated depreciation for buildings

3,000,000

Accumulated amortization of nuclear fuel

2,078,000,000

1,000,000

Exelon Generation Co L L C [Member]

Property Plant And Equipment [Line Items]

Total property, plant and equipment

25,545,000,000

18,788,000,000

Less: accumulated depreciation

^[2]

(6,014,000,000)

(5,313,000,000)

Property, plant and equipment, net

19,531,000,000

13,475,000,000

Property Plant And Equipment Footnotes [Abstract]

Nuclear fuel - work in progress

674

Buildings under capital lease

2,000,000

23,000,000

Original cost basis for buildings

53,000,000

Accumulated depreciation for buildings

30,000,000

Accumulated amortization of nuclear fuel

1,784,000,000

Commonwealth Edison Co [Member]

Property Plant And Equipment [Line Items]

Total property, plant and equipment

16,824,000,000

15,871,000,000

Less: accumulated depreciation

(2,998,000,000)

(2,750,000,000)

Property, plant and equipment, net

13,826,000,000

13,121,000,000

PECO Energy Co [Member]

Property Plant And Equipment [Line Items]

Total property, plant and equipment

8,875,000,000

8,536,000,000

Less: accumulated depreciation

(2,797,000,000)

(2,662,000,000)

Property, plant and equipment, net

6,078,000,000

5,874,000,000

Baltimore Gas and Electric Company [Member]

Property Plant And Equipment [Line Items]

Total property, plant and equipment

8,093,000,000

7,598,000,000

Less: accumulated depreciation

(2,595,000,000)

(2,466,000,000)

Property, plant and equipment, net

$ 5,498,000,000

$ 5,132,000,000

Electric Transmission And Distribution [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.76%

2.59%

2.53%

Electric Transmission And Distribution [Member] | Commonwealth Edison Co [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.67%

2.64%

Electric Transmission And Distribution [Member] | PECO Energy Co [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.51%

2.33%

2.17%

Electric Transmission And Distribution [Member] | Baltimore Gas and Electric Company [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.92%

2.89%

2.88%

Electric Generation Equipment [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

3.15%

3.12%

2.86%

Electric Generation Equipment [Member] | Exelon Generation Co L L C [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

3.12%

2.86%

Gas Distribution Equipment [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.03%

1.73%

1.75%

Gas Distribution Equipment [Member] | PECO Energy Co [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

1.77%

1.73%

1.75%

Gas Distribution Equipment [Member] | Baltimore Gas and Electric Company [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

2.33%

2.41%

2.42%

Common Electric And Gas T And D Equipment [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

7.61%

8.05%

7.25%

Common Electric And Gas T And D Equipment [Member] | PECO Energy Co [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

7.54%

8.05%

7.25%

Common Electric And Gas T And D Equipment [Member] | Baltimore Gas and Electric Company [Member]

Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items]

Annual depreciation rate

7.68%

8.40%

7.24%

[1]	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

Jointly Owned Electric Utility Plant (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($) Miles Voltage	Dec. 31, 2011 USD ($)
Exelon Generation Co L L C [Member] \| Nuclear Generation [Member] \| Quad Cities [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	Generation
Ownership interest	75.00%
Plant	$ 874,000	$ 822,000
Accumulated depreciation	187,000	156,000
Construction work in progress	$ 44,000	37,000
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	75.00%
Plant	$ 874,000	822,000
Exelon Generation Co L L C [Member] \| Nuclear Generation [Member] \| Peach Bottom [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	Generation
Ownership interest	50.00%
Plant	$ 796,000	650,000
Accumulated depreciation	302,000	285,000
Construction work in progress	$ 115,000	111,000
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	50.00%
Plant	$ 796,000	650,000
Exelon Generation Co L L C [Member] \| Nuclear Generation [Member] \| Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	PSEG Nuclear
Ownership interest	42.59%
Plant	$ 494,000	420,000
Accumulated depreciation	119,000	103,000
Construction work in progress	$ 11,000	61,000
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	42.59%
Plant	$ 494,000	420,000
Exelon Generation Co L L C [Member] \| Fossil Fuel Generation [Member] \| Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Plant	3,000	3,000
Jointly Owned Utility Plant Footnote [Abstract]
Plant	$ 3,000	3,000
Exelon Generation Co L L C [Member] \| Fossil Fuel Generation [Member] \| Keystone [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	GenOn
Ownership interest	41.98%
Plant	$ 624,000	366,000
Accumulated depreciation	153,000	137,000
Construction work in progress	$ 10,000	5,000
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	41.98%
Plant	$ 624,000	366,000
Exelon Generation Co L L C [Member] \| Fossil Fuel Generation [Member] \| Conemaugh [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	GenOn
Ownership interest	31.28%
Plant	$ 322,000	271,000
Accumulated depreciation	158,000	154,000
Construction work in progress	$ 57,000	15,000
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	31.28%
Plant	$ 322,000	271,000
Exelon Generation Co L L C [Member] \| Fossil Fuel Generation [Member] \| Wyman [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	FP&L
Ownership interest	5.89%
Plant	$ 3,000	3,000
Accumulated depreciation	3,000	3,000
Construction work in progress	$ 0	0
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	5.89%
Plant	$ 3,000	3,000
Exelon Generation Co L L C [Member] \| Other Service [Member] \| Other Locations [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator
Ownership interest	44.24%
Plant	$ 1,000	1,000
Accumulated depreciation	0	0
Construction work in progress	$ 0	0
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	44.24%
Plant	$ 1,000	1,000
PECO Energy Co [Member] \| Electric Transmission [Member] \| Pennsylvania [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	First Energy
Plant	$ 13,000	5,000
Accumulated depreciation	7,000	3,000
Construction work in progress	1,000	0
Jointly Owned Utility Plant Footnote [Abstract]
Plant	$ 13,000	5,000
Miles of transmission voltage lines \| Miles	127
Transmission line capacity \| Voltage	500
PECO Energy Co [Member] \| Electric Transmission [Member] \| Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	PSEG
Ownership interest	42.55%
Plant	$ 65,000	66,000
Accumulated depreciation	33,000	33,000
Construction work in progress	$ 0	0
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	42.55%
Plant	$ 65,000	$ 66,000
Miles of transmission voltage lines \| Miles	131
Transmission line capacity \| Voltage	500
PECO Energy Co [Member] \| Electric Transmission [Member] \| PA Transmission Lines [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	22.00%
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	22.00%
PECO Energy Co [Member] \| Electric Transmission [Member] \| Conemaugh Substation [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	20.70%
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	20.70%
Transmission line capacity \| Voltage	500
Substation capacity \| Voltage	500
Baltimore Gas and Electric Company [Member] \| Conemaugh Substation [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	10.56%
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	10.56%
Baltimore Gas and Electric Company [Member] \| Electric Transmission [Member] \| Pennsylvania [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	7.00%
Jointly Owned Utility Plant Footnote [Abstract]
Ownership interest	7.00%

Intangible Assets (Details) - USD ($)
$ in Thousands

1 Months Ended

12 Months Ended

Feb. 28, 2003

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

$ 28,000

Future amortization expense in year two

29,000

Future mortizationExpense in year three

29,000

Future amortization expense in year four

29,000

Future amortization expense in year five

29,000

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

576,000

Finite lived intangible assets accumulated amortization

(132,000)

Finite lived intangible assets net

444,000

Finite Lived Intangible Assets Amortization Expense [Abstract]

Intangible asset amortization expense

20,000

$ 19,000

$ 8,000

Exelon Generation Co L L C [Member]

Finite Lived Intangible Assets Amortization Expense [Abstract]

Intangible asset amortization expense

13,000

12,000

1,000

Renewable Energy Credits And Alternative Energy Credits [Abstract]

Noncurrent alternative or renewable energy credits

45,000

6,000

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

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

^[1]

14,000

Future amortization expense in year two

^[1]

14,000

Future mortizationExpense in year three

^[1]

14,000

Future amortization expense in year four

^[1]

14,000

Future amortization expense in year five

^[1]

14,000

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

^[1]

224,000

Finite lived intangible assets accumulated amortization

^[1]

(26,000)

Finite lived intangible assets net

^[1]

198,000

Exelon Generation Co L L C [Member] | Antelope Valley Acquisition [Member]

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

^[2]

7,000

Future amortization expense in year two

^[2]

8,000

Future mortizationExpense in year three

^[2]

8,000

Future amortization expense in year four

^[2]

8,000

Future amortization expense in year five

^[2]

8,000

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

^[2]

190,000

Finite lived intangible assets accumulated amortization

^[2]

Finite lived intangible assets net

^[2]

190,000

Commonwealth Edison Co [Member]

Finite Lived Intangible Assets Footnotes [Abstract]

2003 City of Chicago payment made to 3rd party

$ (2,000)

2003 City of Chicago payment received

32,000

2003 City of Chicago payment made to city

(60,000)

Reduction of amortization expense

$ (2,000)

Finite Lived Intangible Assets Amortization Expense [Abstract]

Intangible asset amortization expense

7,000

$ 7,000

Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member]

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

^[3]

3,000

Future amortization expense in year two

^[3]

3,000

Future mortizationExpense in year three

^[3]

3,000

Future amortization expense in year four

^[3]

3,000

Future amortization expense in year five

^[3]

4,000

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

^[3]

100,000

Finite lived intangible assets accumulated amortization

^[3]

(72,000)

Finite lived intangible assets net

^[3]

28,000

Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member]

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

Future amortization expense within the next twelve months

^[4]

4,000

Future amortization expense in year two

^[4]

4,000

Future mortizationExpense in year three

^[4]

4,000

Future amortization expense in year four

^[4]

4,000

Future amortization expense in year five

^[4]

3,000

Finite Lived Intangible Assets Net [Abstract]

Finite lived intangible assets gross

^[4]

62,000

Finite lived intangible assets accumulated amortization

^[4]

(34,000)

Finite lived intangible assets net

^[4]

28,000

PECO Energy Co [Member]

Renewable Energy Credits And Alternative Energy Credits [Abstract]

Current alternative or renewable energy credits

17,000

14,000

Noncurrent alternative or renewable energy credits

$ 9,000

$ 16,000

[1]	Refer to Note 4 – Merger and Acquisitions for additional information regarding Exelon Wind.
[2]	Refer to Note 4 – Merger and Acquisitions for additional information regarding Antelope Valley.
[3]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd's franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
[4]	In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third party on the City of Chicago's behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation's obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.

Fair Value of Financial Assets and Liabilities (Fair Value By Balance Sheet Grouping) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt to financing trusts	$ 648,000	$ 390,000
Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	214,000	737,000
Long-term debt (including amounts due within one year)	18,745,000	12,627,000
Long-term debt to financing trusts	648,000	390,000
Spent nuclear fuel obligation	1,020,000	1,019,000
Preferred securities of subsidiary	87,000	87,000
Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		737,000
Long-term debt (including amounts due within one year)		14,488,000
Long-term debt to financing trusts		358,000
Spent nuclear fuel obligation		886,000
Preferred securities of subsidiary		79,000
Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 1 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	4,000
Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 2 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	210,000
Long-term debt (including amounts due within one year)	20,244,000
Spent nuclear fuel obligation	763,000
Preferred securities of subsidiary	82,000
Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 3 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	276,000
Long-term debt to financing trusts	664,000
Exelon Generation Co L L C [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		2,000
Long-term debt (including amounts due within one year)	7,483,000	3,677,000
Spent nuclear fuel obligation	1,020,000	1,019,000
Exelon Generation Co L L C [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		2,000
Long-term debt (including amounts due within one year)		4,231,000
Spent nuclear fuel obligation		886,000
Exelon Generation Co L L C [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 2 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	7,591,000
Spent nuclear fuel obligation	763,000
Exelon Generation Co L L C [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 3 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	258,000
Commonwealth Edison Co [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	5,567,000	5,665,000
Long-term debt to financing trusts	206,000	206,000
Commonwealth Edison Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)		6,540,000
Long-term debt to financing trusts		184,000
Commonwealth Edison Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 2 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	6,530,000
Commonwealth Edison Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 3 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	18,000
Long-term debt to financing trusts	212,000
PECO Energy Co [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt to financing trusts	184,000	184,000
PECO Energy Co [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	210,000	225,000
Long-term debt (including amounts due within one year)	1,947,000	1,972,000
Long-term debt to financing trusts	184,000	184,000
Preferred securities of subsidiary	87,000	87,000
PECO Energy Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		225,000
Long-term debt (including amounts due within one year)		2,295,000
Long-term debt to financing trusts		174,000
Preferred securities of subsidiary		79,000
PECO Energy Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 2 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	210,000
Long-term debt (including amounts due within one year)	2,264,000
Preferred securities of subsidiary	82,000
PECO Energy Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 3 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt to financing trusts	188,000
Baltimore Gas and Electric Company [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	2,178,000	2,101,000
Long-term debt to financing trusts	258,000	258,000
Baltimore Gas and Electric Company [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)		2,377,000
Long-term debt to financing trusts		$ 256,000
Baltimore Gas and Electric Company [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 2 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	2,468,000
Baltimore Gas and Electric Company [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member] \| Fair Value Inputs Level 3 [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Long-term debt to financing trusts	$ 263,000

Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

^[1]

$ 995,000

$ 861,000

Fixed income [Abstract]

Debt securities issued by foreign governments

16,000

Deferred compensation

(102,000)

(73,000)

Total assets

10,785,000

9,268,000

Total liabilities

(735,000)

(311,000)

Total net assets

10,050,000

8,957,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

102,000

73,000

Mark-to-market derivative liabilities (current liabilities)

352,000

112,000

Mark-to-market derivative liabilities (noncurrent liabilities)

281,000

126,000

Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

245,000

562,000

Equity Securities [Abstract]

Equity securities

1,480,000

1,275,000

Commingled funds

1,933,000

1,822,000

Equity securities subtotal

3,413,000

3,097,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,057,000

1,047,000

Debt securities issued by states of the United States and political subdivisions of the states

321,000

541,000

Debt securities issued by foreign governments

93,000

16,000

Corporate debt securities

1,788,000

778,000

Federal agency mortgage-backed securities

24,000

357,000

Commercial mortgage-backed securities (non-agency)

45,000

83,000

Residential mortgage-backed securities (non-agency)

11,000

5,000

Mutual funds fixed income

23,000

47,000

Fixed income subtotal

3,362,000

2,874,000

Direct lending securities

183,000

Other debt obligations

15,000

18,000

Nuclear decommissioning trust fund investments subtotal

^[2]

7,218,000

6,564,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

30,000

(57,000)

Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

23,000

Equity Securities [Abstract]

Equity securities

14,000

35,000

Commingled funds

9,000

30,000

Equity securities subtotal

23,000

65,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

130,000

80,000

Debt securities issued by states of the United States and political subdivisions of the states

37,000

65,000

Corporate debt securities

249,000

314,000

Federal agency mortgage-backed securities

49,000

121,000

Commercial mortgage-backed securities (non-agency)

6,000

10,000

Residential mortgage-backed securities (non-agency)

89,000

Commingled funds fixed income

20,000

Fixed income subtotal

471,000

610,000

Direct lending securities

37,000

Other debt obligations

1,000

13,000

Pledged assets for Zion Station decommissioning subtotal

^[3]

607,000

725,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from pledged assets

7,000

9,000

Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

2,000

Fixed income [Abstract]

Mutual funds

69,000

34,000

^[4],[5]

Rabbi trust investments subtotal

71,000

36,000

Deferred compensation

(53,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

53,000

Supplemental executive retirement plan fair value

16,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

28,000

25,000

Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Other investments

19,000

Commodity Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Cash flow hedges

857,000

Other derivatives

4,675,000

1,777,000

Proprietary trading

3,193,000

288,000

Effect of netting and allocation of collateral received/(paid)

(6,056,000)

^[4]

(1,855,000)

^[6]

Mark-to-market subtotal

1,812,000

1,067,000

^[4]

Commodity Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Cash flow hedges

(13,000)

Other derivatives

(3,566,000)

(1,257,000)

Proprietary trading

(3,121,000)

(264,000)

Effect of netting and allocation of collateral received/(paid)

^[4]

6,087,000

1,315,000

Mark-to-market subtotal

(600,000)

(219,000)

^[6]

Interest Rate Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Effect of netting and allocation of collateral received/(paid)

51,000

Interest rate mark to market

114,000

15,000

Interest rate marrk-to-market Subtotal

63,000

Interest Rate Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Effect of netting and allocation of collateral received/(paid)

(51,000)

Interest rate mark to market

(84,000)

(19,000)

Interest rate marrk-to-market Subtotal

(33,000)

Fair Value Inputs Level 1 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

^[1]

995,000

861,000

Fixed income [Abstract]

Total assets

3,837,000

Total liabilities

(83,000)

(1,000)

Total net assets

3,979,000

3,836,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Collateral received from counterparties, net of collateral paid to counterparties

219,000

Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

245,000

562,000

Equity Securities [Abstract]

Equity securities

1,480,000

1,275,000

Equity securities subtotal

1,480,000

1,275,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,057,000

1,014,000

Fixed income subtotal

1,057,000

1,014,000

Nuclear decommissioning trust fund investments subtotal

^[2]

2,782,000

2,851,000

Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Equity Securities [Abstract]

Equity securities

14,000

35,000

Equity securities subtotal

14,000

35,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

118,000

54,000

Fixed income subtotal

118,000

54,000

Pledged assets for Zion Station decommissioning subtotal

^[3]

132,000

89,000

Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

2,000

Fixed income [Abstract]

Mutual funds

69,000

34,000

^[4],[5]

Rabbi trust investments subtotal

71,000

36,000

Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Other investments

2,000

Total assets

4,062,000

Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Other derivatives

861,000

Proprietary trading

1,042,000

Effect of netting and allocation of collateral received/(paid)

^[4]

(1,823,000)

Mark-to-market subtotal

80,000

Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Other derivatives

(1,041,000)

(1,000)

Proprietary trading

(1,084,000)

Effect of netting and allocation of collateral received/(paid)

^[4]

2,042,000

Mark-to-market subtotal

(83,000)

(1,000)

^[6]

Fair Value Inputs Level 2 [Member]

Fixed income [Abstract]

Deferred compensation

(102,000)

(73,000)

Total assets

5,237,000

Total liabilities

(363,000)

(183,000)

Total net assets

5,415,000

5,054,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

102,000

73,000

Collateral received from counterparties, net of collateral paid to counterparties

(155,000)

532,000

Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Equity Securities [Abstract]

Commingled funds

1,933,000

1,822,000

Equity securities subtotal

1,933,000

1,822,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

33,000

Debt securities issued by states of the United States and political subdivisions of the states

321,000

541,000

Debt securities issued by foreign governments

93,000

Corporate debt securities

1,788,000

778,000

Federal agency mortgage-backed securities

24,000

357,000

Commercial mortgage-backed securities (non-agency)

45,000

83,000

Residential mortgage-backed securities (non-agency)

11,000

5,000

Mutual funds fixed income

23,000

47,000

Fixed income subtotal

2,305,000

1,860,000

Other debt obligations

15,000

18,000

Nuclear decommissioning trust fund investments subtotal

^[2]

4,253,000

3,700,000

Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

23,000

Equity Securities [Abstract]

Commingled funds

9,000

30,000

Equity securities subtotal

9,000

30,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

12,000

26,000

Debt securities issued by states of the United States and political subdivisions of the states

37,000

65,000

Corporate debt securities

249,000

314,000

Federal agency mortgage-backed securities

49,000

121,000

Commercial mortgage-backed securities (non-agency)

6,000

10,000

Commingled funds fixed income

20,000

Fixed income subtotal

353,000

556,000

Other debt obligations

1,000

13,000

Pledged assets for Zion Station decommissioning subtotal

^[3]

386,000

599,000

Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total assets

5,778,000

Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Cash flow hedges

857,000

Other derivatives

3,173,000

1,653,000

Proprietary trading

2,078,000

240,000

Effect of netting and allocation of collateral received/(paid)

(4,175,000)

^[4]

(1,827,000)

^[6]

Mark-to-market subtotal

1,076,000

923,000

^[4]

Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Cash flow hedges

(13,000)

Other derivatives

(2,289,000)

(1,137,000)

Proprietary trading

(1,959,000)

(236,000)

Effect of netting and allocation of collateral received/(paid)

^[4]

4,020,000

1,295,000

Mark-to-market subtotal

(228,000)

(91,000)

^[6]

Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Effect of netting and allocation of collateral received/(paid)

51,000

Interest rate mark to market

114,000

15,000

Interest rate marrk-to-market Subtotal

63,000

Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Effect of netting and allocation of collateral received/(paid)

(51,000)

Interest rate mark to market

(84,000)

(19,000)

Interest rate marrk-to-market Subtotal

(33,000)

Fair Value Inputs Level 3 [Member]

Fixed income [Abstract]

Total assets

194,000

Total liabilities

(289,000)

(127,000)

Total net assets

656,000

67,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Collateral received from counterparties, net of collateral paid to counterparties

(33,000)

8,000

Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fixed income [Abstract]

Direct lending securities

183,000

Nuclear decommissioning trust fund investments subtotal

^[2]

183,000

13,000

Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fixed income [Abstract]

Residential mortgage-backed securities (non-agency)

89,000

Direct lending securities

37,000

Pledged assets for Zion Station decommissioning subtotal

^[3]

89,000

37,000

Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Other investments

17,000

Total assets

945,000

Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value of energy swap contract current liability

18,000

9,000

Fair value of energy swap contract noncurrent liability

49,000

97,000

Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]

Fixed income [Abstract]

Other derivatives

641,000

124,000

Proprietary trading

73,000

48,000

Effect of netting and allocation of collateral received/(paid)

(58,000)

^[4]

(28,000)

^[6]

Mark-to-market subtotal

656,000

144,000

^[4]

Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

Fixed income [Abstract]

Other derivatives

(236,000)

(119,000)

Proprietary trading

(78,000)

(28,000)

Effect of netting and allocation of collateral received/(paid)

^[4]

25,000

20,000

Mark-to-market subtotal

(289,000)

(127,000)

^[6]

Exelon Generation Co L L C [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Mark-to-market derivative liabilities (current liabilities)

334,000

103,000

Mark-to-market derivative liabilities (noncurrent liabilities)

232,000

29,000

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

245,000

562,000

Equity Securities [Abstract]

Equity securities

1,480,000

1,275,000

Commingled funds

1,933,000

1,822,000

Equity securities subtotal

3,413,000

3,097,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,057,000

1,047,000

Debt securities issued by states of the United States and political subdivisions of the states

321,000

541,000

Debt securities issued by foreign governments

93,000

16,000

Corporate debt securities

1,788,000

778,000

Federal agency mortgage-backed securities

24,000

357,000

Commercial mortgage-backed securities (non-agency)

45,000

83,000

Residential mortgage-backed securities (non-agency)

11,000

5,000

Mutual funds fixed income

23,000

47,000

Fixed income subtotal

3,362,000

2,874,000

Direct lending securities

183,000

13,000

Other debt obligations

15,000

18,000

Nuclear decommissioning trust fund investments subtotal

7,218,000

6,564,000

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

23,000

Equity Securities [Abstract]

Equity securities

14,000

35,000

Commingled funds

9,000

30,000

Equity securities subtotal

23,000

65,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

130,000

80,000

Debt securities issued by states of the United States and political subdivisions of the states

37,000

65,000

Corporate debt securities

249,000

314,000

Federal agency mortgage-backed securities

49,000

121,000

Commercial mortgage-backed securities (non-agency)

6,000

10,000

Commingled funds fixed income

20,000

Fixed income subtotal

471,000

610,000

Direct lending securities

89,000

37,000

Other debt obligations

1,000

13,000

Pledged assets for Zion Station decommissioning subtotal

607,000

725,000

Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

1,000

Fixed income [Abstract]

Mutual funds

13,000

Rabbi trust investments subtotal

14,000

4,000

Exelon Generation Co L L C [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

487,000

466,000

Fixed income [Abstract]

Cash flow hedges

1,551,000

Other derivatives

4,901,000

1,777,000

Proprietary trading

3,193,000

288,000

Effect of netting and allocation of collateral received/(paid)

6,056,000

1,855,000

Mark-to-market subtotal

2,038,000

1,761,000

Interest rate mark to market

50,000

Other investments

19,000

Total assets

10,433,000

9,520,000

Total net assets

9,839,000

9,370,000

Exelon Generation Co L L C [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Cash flow hedges

(13,000)

Other derivatives

(3,499,000)

(1,151,000)

Proprietary trading

(3,121,000)

(264,000)

Effect of netting and allocation of collateral received/(paid)

6,087,000

1,315,000

Mark-to-market subtotal

(533,000)

(113,000)

Interest rate mark to market

(33,000)

(19,000)

Deferred compensation

(28,000)

18,000

Total liabilities

(594,000)

(150,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

28,000

(18,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

245,000

562,000

Equity Securities [Abstract]

Equity securities

1,480,000

1,275,000

Equity securities subtotal

1,480,000

1,275,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,057,000

1,014,000

Fixed income subtotal

1,057,000

1,014,000

Nuclear decommissioning trust fund investments subtotal

2,782,000

2,851,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Equity Securities [Abstract]

Equity securities

14,000

35,000

Equity securities subtotal

14,000

35,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

118,000

54,000

Fixed income subtotal

118,000

54,000

Pledged assets for Zion Station decommissioning subtotal

132,000

89,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

1,000

Fixed income [Abstract]

Mutual funds

13,000

Rabbi trust investments subtotal

14,000

4,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

487,000

466,000

Fixed income [Abstract]

Other derivatives

861,000

Proprietary trading

1,042,000

Effect of netting and allocation of collateral received/(paid)

1,823,000

Mark-to-market subtotal

80,000

Other investments

2,000

Total assets

3,497,000

3,410,000

Total net assets

3,414,000

3,409,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Other derivatives

(1,041,000)

(1,000)

Proprietary trading

(1,084,000)

Effect of netting and allocation of collateral received/(paid)

2,042,000

Mark-to-market subtotal

(83,000)

(1,000)

Total liabilities

(83,000)

(1,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Equity Securities [Abstract]

Commingled funds

1,933,000

1,822,000

Equity securities subtotal

1,933,000

1,822,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

33,000

Debt securities issued by states of the United States and political subdivisions of the states

321,000

541,000

Debt securities issued by foreign governments

93,000

16,000

Corporate debt securities

1,788,000

778,000

Federal agency mortgage-backed securities

24,000

357,000

Commercial mortgage-backed securities (non-agency)

45,000

83,000

Residential mortgage-backed securities (non-agency)

11,000

5,000

Mutual funds fixed income

23,000

47,000

Fixed income subtotal

2,305,000

1,860,000

Other debt obligations

15,000

18,000

Nuclear decommissioning trust fund investments subtotal

4,253,000

3,700,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

23,000

Equity Securities [Abstract]

Commingled funds

9,000

30,000

Equity securities subtotal

9,000

30,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

12,000

26,000

Debt securities issued by states of the United States and political subdivisions of the states

37,000

65,000

Corporate debt securities

249,000

314,000

Federal agency mortgage-backed securities

49,000

121,000

Commercial mortgage-backed securities (non-agency)

6,000

10,000

Commingled funds fixed income

20,000

Fixed income subtotal

353,000

556,000

Other debt obligations

1,000

13,000

Pledged assets for Zion Station decommissioning subtotal

386,000

599,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Cash flow hedges

857,000

Other derivatives

3,173,000

1,653,000

Proprietary trading

2,078,000

240,000

Effect of netting and allocation of collateral received/(paid)

4,175,000

1,827,000

Mark-to-market subtotal

1,076,000

923,000

Interest rate mark to market

50,000

Total assets

5,765,000

5,222,000

Total net assets

5,476,000

5,094,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Cash flow hedges

(13,000)

Other derivatives

(2,289,000)

(1,137,000)

Proprietary trading

(1,959,000)

(236,000)

Effect of netting and allocation of collateral received/(paid)

4,020,000

1,295,000

Mark-to-market subtotal

(228,000)

(91,000)

Interest rate mark to market

(33,000)

(19,000)

Deferred compensation

(28,000)

18,000

Total liabilities

(289,000)

(128,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

28,000

(18,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fixed income [Abstract]

Direct lending securities

183,000

13,000

Nuclear decommissioning trust fund investments subtotal

183,000

13,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fixed income [Abstract]

Direct lending securities

89,000

37,000

Pledged assets for Zion Station decommissioning subtotal

89,000

37,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Cash flow hedges

694,000

Other derivatives

867,000

124,000

Proprietary trading

73,000

48,000

Effect of netting and allocation of collateral received/(paid)

58,000

28,000

Mark-to-market subtotal

882,000

838,000

Other investments

17,000

Total assets

1,171,000

888,000

Total net assets

949,000

867,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Other derivatives

(169,000)

(13,000)

Proprietary trading

(78,000)

(28,000)

Effect of netting and allocation of collateral received/(paid)

25,000

20,000

Mark-to-market subtotal

(222,000)

(21,000)

Total liabilities

(222,000)

(21,000)

Commonwealth Edison Co [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Mark-to-market derivative liabilities (current liabilities)

18,000

9,000

Mark-to-market derivative liabilities (noncurrent liabilities)

49,000

97,000

Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

2,000

Fixed income [Abstract]

Mutual funds

8,000

19,000

Rabbi trust investments subtotal

8,000

21,000

Commonwealth Edison Co [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

111,000

173,000

Fixed income [Abstract]

Total assets

119,000

194,000

Total net assets

(182,000)

(614,000)

Commonwealth Edison Co [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Mark-to-market subtotal

(293,000)

(800,000)

Deferred compensation

8,000

Total liabilities

301,000

808,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

(8,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

2,000

Fixed income [Abstract]

Mutual funds

8,000

19,000

Rabbi trust investments subtotal

8,000

21,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

111,000

173,000

Fixed income [Abstract]

Total assets

119,000

194,000

Total net assets

119,000

194,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total net assets

(8,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Deferred compensation

8,000

Total liabilities

8,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

(8,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total net assets

(293,000)

(800,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Mark-to-market subtotal

(293,000)

(800,000)

Total liabilities

293,000

800,000

PECO Energy Co [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liabilities (noncurrent liabilities)

PECO Energy Co [Member] | Rabbi Trust Investments [Member]

Fixed income [Abstract]

Mutual funds

9,000

PECO Energy Co [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

(346,000)

175,000

Fixed income [Abstract]

Total assets

355,000

184,000

Total net assets

337,000

163,000

PECO Energy Co [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Mark-to-market subtotal

Deferred compensation

18,000

21,000

Total liabilities

18,000

21,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

(18,000)

(21,000)

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fixed income [Abstract]

Mutual funds

9,000

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

(346,000)

175,000

Fixed income [Abstract]

Total assets

355,000

184,000

Total net assets

355,000

184,000

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Fixed income [Abstract]

Mutual funds

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total assets

Total net assets

(18,000)

(21,000)

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Deferred compensation

18,000

21,000

Total liabilities

18,000

21,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

(18,000)

(21,000)

PECO Energy Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total net assets

PECO Energy Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Mark-to-market subtotal

Total liabilities

Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member]

Fixed income [Abstract]

Mutual funds

5,000

Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

33,000

Fixed income [Abstract]

Total assets

38,000

33,000

Total net assets

33,000

Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Deferred compensation

5,000

Total liabilities

5,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

(5,000)

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fixed income [Abstract]

Mutual funds

5,000

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash equivalents

33,000

Fixed income [Abstract]

Total assets

38,000

33,000

Total net assets

38,000

$ 33,000

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Total net assets

(5,000)

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Deferred compensation

5,000

Total liabilities

5,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Deferred compensation

$ (5,000)

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[2]	Excludes net assets (liabilities) of $30 million and $(57) million at December 31, 2012 and December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[3]	Excludes net assets of $7 million and $9 million at December 31, 2012 and December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[4]	Excludes $28 million and $25 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.
[5]	The mutual funds held by the Rabbi trusts include $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan. These funds are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.
[6]	Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $532 million and $8 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2011.

Fair Value of Financial Assets and Liabilities (Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

$ 67,000

Total realized / unrealized gains (losses)

Included in income

(119,000)

Included in other comprehensive income

Included in regulatory assets

40,000

Change in collateral

(32,000)

$ 6,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

583,000

Sales

(11,000)

Transfers out of Level 3 - (Asset) / Liability

89,000

Ending balance

656,000

67,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

37,000

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

(156,000)

Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

67,000

50,000

Total realized / unrealized gains (losses)

Included in income

100,000

Included in other comprehensive income

(25,000)

Included in regulatory assets

(104,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

80,000

Sales

(23,000)

Transfers into Level 3 - (Asset) / Liability

39,000

Transfers out of Level 3 - (Asset) / Liability

(17,000)

Ending balance

67,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

132,000

Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

13,000

Total realized / unrealized gains (losses)

Included in income

Included in other comprehensive income

Included in regulatory assets

1,000

Change in collateral

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

169,000

Sales

Transfers out of Level 3 - (Asset) / Liability

Ending balance

183,000

13,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

13,000

Total realized / unrealized gains (losses)

Included in income

1,000

Included in regulatory assets

2,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

10,000

Ending balance

13,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

1,000

Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

37,000

Total realized / unrealized gains (losses)

Included in income

Included in other comprehensive income

Included in regulatory assets

Change in collateral

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

63,000

Sales

(11,000)

Transfers out of Level 3 - (Asset) / Liability

Ending balance

89,000

37,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

37,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

60,000

(23,000)

37,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

17,000

Total realized / unrealized gains (losses)

Included in income

^[1]

(119,000)

Included in regulatory assets

39,000

Change in collateral

(32,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

334,000

Sales

Transfers out of Level 3 - (Asset) / Liability

89,000

Ending balance

367,000

17,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

37,000

Derivative [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

17,000

50,000

Total realized / unrealized gains (losses)

Included in income

99,000

Included in other comprehensive income

^[1]

(25,000)

Included in regulatory assets

^[2]

(106,000)

Change in collateral

6,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

10,000

Transfers into Level 3 - (Asset) / Liability

39,000

Transfers out of Level 3 - (Asset) / Liability

(17,000)

Ending balance

17,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

131,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair value of Constellation fair value assets acquired

323,000

Acquisition of marketable securities

17,000

Other Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

17,000

Ending balance

17,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

867,000

1,030,000

Total realized / unrealized gains (losses)

Included in income

(112,000)

(100,000)

Included in other comprehensive income

475,000

311,000

Included in payable for Zion Station decommissioning

(2,000)

Included in noncurrent payables to affiliates

(1,000)

Change in collateral

32,000

(6,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

583,000

80,000

Sales

11,000

23,000

Transfers into Level 3 - (Asset) / Liability

(39,000)

Transfers out of Level 3 - (Asset) / Liability

89,000

(17,000)

Ending balance

949,000

867,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

(12,000)

(132,000)

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

13,000

Total realized / unrealized gains (losses)

Included in income

(1,000)

Included in payable for Zion Station decommissioning

(2,000)

Included in noncurrent payables to affiliates

(1,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

169,000

10,000

Ending balance

183,000

13,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

(1,000)

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

37,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

63,000

60,000

Sales

11,000

23,000

Ending balance

89,000

37,000

Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

817,000

1,030,000

Total realized / unrealized gains (losses)

Included in income

(112,000)

^[1]

(99,000)

Included in other comprehensive income

475,000

311,000

Change in collateral

32,000

(6,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

334,000

10,000

Transfers into Level 3 - (Asset) / Liability

(39,000)

Transfers out of Level 3 - (Asset) / Liability

89,000

(17,000)

Ending balance

660,000

817,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

(12,000)

(131,000)

Exelon Generation Co L L C [Member] | Other Investments [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Purchases

17,000

Ending balance

17,000

Commonwealth Edison Co [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

(800,000)

(971,000)

Total realized / unrealized gains (losses)

Included in regulatory assets

507,000

171,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Ending balance

(293,000)

(800,000)

PECO Energy Co [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Beginning balance

$ 0

(9,000)

Total realized / unrealized gains (losses)

Included in regulatory assets

9,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Ending balance

$ 0

[1]

Includes the reclassification of $156 million of realized losses due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

[2]

Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI.

Fair Value of Financial Assets and Liabilities (Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings) (Details) - Fair Value Inputs Level 3 [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
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	$ (153,000)	$ 108,000
Change in the unrealized gains (losses) relating to assets and liabilities held	13,000	137,000
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	34,000	(8,000)
Change in the unrealized gains (losses) relating to assets and liabilities held	24,000	(5,000)
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	(146,000)	108,000
Change in the unrealized gains (losses) relating to assets and liabilities held	(25,000)	137,000
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	34,000	(8,000)
Change in the unrealized gains (losses) relating to assets and liabilities held	$ 13,000	$ (5,000)

Fair Value of Financial Assets and Liabilities (Fair Value Inputs Assets Quantitative Information) (Details) - Fair Value Inputs Level 3 [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($)
Business Intersegment Transactions [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 226,000
Business Intersegment Transactions [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	8.00%
Business Intersegment Transactions [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	9.00%
Exelon Generation Co L L C [Member] \| Derivative [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 473,000
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	14,000
Forward gas price assets	3,260
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	79,000
Forward gas price assets	$ 6,270
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	28.00%
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	132.00%
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Net	$ (6,000)
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price liabilities	15,000
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price liabilities	$ 106,000
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	16.00%
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	48.00%
Commonwealth Edison Co [Member] \| Derivative [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Net	$ (67,000)
Commonwealth Edison Co [Member] \| Derivative [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	8.30%
Commonwealth Edison Co [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	3.50%
Forward heat rate	8.00%
Renewable factor	81.00%
Commonwealth Edison Co [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward heat rate	9.50%
Renewable factor	123.00%

Derivative Financial Instruments (Commodity Price Risk) (Details)	12 Months Ended
	Dec. 31, 2012 MW GWH	Dec. 31, 2011 GWH	Dec. 31, 2010 GWH
Maximum [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged	20.00%
Exelon Generation Co L L C [Member]
Swap Contract Volumes [Abstract]
Swap contract volumes \| MW	3,000
Proprietary Trading Volumes [Abstract]
Proprietary trading activities volume \| GWH	12,958	5,742	3,625
Exelon Generation Co L L C [Member] \| Minimum [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Expected generation hedged in next twelve months	94.00%
Expected generation hedged in year two	62.00%
Expected generation hedged in year three	27.00%
Exelon Generation Co L L C [Member] \| Maximum [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Expected generation hedged in next twelve months	97.00%
Expected generation hedged in year two	65.00%
Expected generation hedged in year three	30.00%
PECO Energy Co [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged	30.00%
Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged	10.00%

Derivative Financial Instruments (Interest Rate Risk) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Mar. 12, 2012 USD ($)
Cost Of Capital Strategies [Abstract]
Hypothetical increase in interest rates associated with variable-rate debt	50.00%
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound	$ 2,000
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (current assets)	4,000
Mark-to-market derivative assets (noncurrent assets)	59,000
Total mark-to-market derivative assets	63,000
Mark-to-market derivative liabilities (current liabilities)	(2,000)
Mark-to-market derivative liabilities (noncurrent liabilities)	(31,000)
Total mark-to-market derivative liabilities	(33,000)
Total mark-to-market derivative net assets (liabilities)	30,000
Interest Rate Risk - Fair Value Hedges [Abstract]
Notional amounts of fair value hedges outstanding related to interest rate swaps	650,000	$ 100,000
Interest rate swaps previously held by acquiree				$ 550,000
Fair value of interest rate swaps from merger acquiree	150,000			$ 44,000
Interest Rate Risk - Cash Flow Hedges [Abstract]
Mark-to-market derivative liabilities	281,000	126,000
Unrealized Gain (Loss) on Derivatives	604,000	(291,000)	$ 88,000
Interest Expense [Member]
Derivative Instruments Gain Loss Recognized In Income Net [Abstract]
Loss on swaps/borrowings	(6,000)	(1,000)	(4,000)
Interest Rate Risk - Cash Flow Hedges [Abstract]
Unrealized Gain (Loss) on Derivatives	5,000
Designated as Hedging Instrument [Member]
Interest Rate Risk - Fair Value Hedges [Abstract]
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments	49,000	15,000
Interest Rate Risk - Cash Flow Hedges [Abstract]
Notional amount of interest rate cash flow hedge derivatives	800,000
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives	452,000
Notional amounts on forward starting interest rate swaps	75,000
Designated as Hedging Instrument [Member] \| Interest Expense [Member]
Derivative Instruments Gain Loss Recognized In Income Net [Abstract]
Gain on swaps/borrowings		1,000	4,000
Interest Rate Risk - Fair Value Hedges [Abstract]
Notional amounts of fair value hedges outstanding related to interest rate swaps	(6,000)
Interest Rate Risk - Cash Flow Hedges [Abstract]
Pre-tax gain/loss on interest rate cash flow hedges	(12,000)
Derivative [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (noncurrent assets)	1,000
Exelon Generation Co L L C [Member]
Cost Of Capital Strategies [Abstract]
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound	2,000
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (current assets)	4,000
Mark-to-market derivative assets (noncurrent assets)	46,000
Total mark-to-market derivative assets	50,000
Mark-to-market derivative liabilities (current liabilities)	(2,000)
Mark-to-market derivative liabilities (noncurrent liabilities)	(31,000)
Total mark-to-market derivative liabilities	(33,000)
Total mark-to-market derivative net assets (liabilities)	17,000
Interest Rate Risk - Cash Flow Hedges [Abstract]
DOE loan guarantee	646,000
DOE interest rate swap	485,000
Mark-to-market derivative liabilities	232,000	29,000
Unrealized Gain (Loss) on Derivatives	611,000	$ (291,000)	$ 88,000
Exelon Generation Co L L C [Member] \| Antelope Valley Project [Member]
Interest Rate Risk - Cash Flow Hedges [Abstract]
Notional amount of interest rate cash flow hedge derivatives	$ 485,000
Percentage of interest rate swap in relation to DOE guarantee	75
Notional amount of interest rate swap DOE advance	$ 165,000
Percent of DOE loan advance offset	75.00%
Notional amount of remaining cash flow hedges	$ 320,000
Mark-to-market derivative liabilities	28,000
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (noncurrent assets)	38,000
Total mark-to-market derivative assets	38,000
Mark-to-market derivative liabilities (current liabilities)	(1,000)
Mark-to-market derivative liabilities (noncurrent liabilities)	(31,000)
Total mark-to-market derivative liabilities	(32,000)
Total mark-to-market derivative net assets (liabilities)	6,000
Interest Rate Risk - Fair Value Hedges [Abstract]
Notional amount of interest rate swaps acquired from merger	29,000
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Other Solar Projects [Member]
Interest Rate Risk - Cash Flow Hedges [Abstract]
Notional amounts on forward starting interest rate swaps	29,000
Exelon Generation Co L L C [Member] \| Derivative [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (current assets)	3,000
Mark-to-market derivative assets (noncurrent assets)	8,000
Total mark-to-market derivative assets	11,000
Mark-to-market derivative liabilities (current liabilities)	(1,000)
Total mark-to-market derivative liabilities	(1,000)
Total mark-to-market derivative net assets (liabilities)	10,000
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (current assets)	20,000
Mark-to-market derivative assets (noncurrent assets)	32,000
Total mark-to-market derivative assets	52,000
Mark-to-market derivative liabilities (current liabilities)	(19,000)
Mark-to-market derivative liabilities (noncurrent liabilities)	(32,000)
Total mark-to-market derivative liabilities	(51,000)
Total mark-to-market derivative net assets (liabilities)	1,000
Exelon Generation Co L L C [Member] \| Collateral And Netting [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (current assets)	(19,000)
Mark-to-market derivative assets (noncurrent assets)	(32,000)
Total mark-to-market derivative assets	(51,000)
Mark-to-market derivative liabilities (current liabilities)	19,000
Mark-to-market derivative liabilities (noncurrent liabilities)	32,000
Total mark-to-market derivative liabilities	51,000
Total mark-to-market derivative net assets (liabilities)	0
Other Segment [Member] \| Designated as Hedging Instrument [Member]
Derivative Interest Rate Risk [Abstract]
Mark-to-market derivative assets (noncurrent assets)	13,000
Total mark-to-market derivative assets	13,000
Mark-to-market derivative liabilities (noncurrent liabilities)	(4,000)
Total mark-to-market derivative net assets (liabilities)	$ 13,000

Derivative Financial Instruments (Fair Value Measurments) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

$ 934,000

$ 432,000

Mark-to-market derivative assets (noncurrent assets)

878,000

650,000

Total mark-to-market derivative assets

1,812,000

1,082,000

Mark-to-market derivative liabilities (current liabilities)

350,000

112,000

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

250,000

107,000

Total mark-to-market derivative liabilities

600,000

219,000

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

1,212,000

863,000

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Change in fair value

(241,000)

218,000

Reclassification to realized at settlement

768,000

(515,000)

Net mark-to-market gains (losses)

527,000

(297,000)

Proprietary Trading Activities [Abstract]

Net mark-to-market gains (losses)

(3,000)

Pro Forma [Member]

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Change in fair value

218,000

389,000

Reclassification to realized at settlement

(515,000)

(304,000)

Net mark-to-market gains (losses)

(297,000)

85,000

Total Cash Flow Hedges [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Accumulated OCI derivative gain - Beginning Balance

488,000

400,000

Effective portion of changes in fair value

^[1]

330,000

402,000

Accumulated OCI derivative gain - Ending Balance

368,000

488,000

$ 400,000

Cash Flow Hedge Activity Impact [Abstract]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

747,000

512,000

754,000

Total Cash Flow Hedges [Member] | Operating Revenue [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(453,000)

(309,000)

Ineffective portion recognized in income

3,000

Cash Flow Hedge Activity Impact [Abstract]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

(5,000)

10,000

1,000

Total Cash Flow Hedges [Member] | Purchased Power [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Ineffective portion recognized in income

(5,000)

Exelon Generation Co L L C [Member]

Cash Flow Hedge Activity Impact [Abstract]

Net unrealized pre-tax gain (loss) on effective cash flow hedges

1,928,000

Net unrealized pre-tax gain (loss) on effective cash flow hedges related to swap contract

693,000

Expected reclassification from accumulated other comprehensive income to results of operations

684,000

Expected reclassification from accumulated other comprehensive income to results of operations related to fair value of swap contracts

219,000

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

934,000

432,000

Mark-to-market derivative assets with affiliate (current assets)

226,000

503,000

Mark-to-market derivative assets (noncurrent assets)

878,000

635,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

191,000

Total mark-to-market derivative assets

2,038,000

1,761,000

Mark-to-market derivative liabilities (current liabilities)

332,000

103,000

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

201,000

10,000

Total mark-to-market derivative liabilities

533,000

113,000

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

1,505,000

1,648,000

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Change in fair value

(147,000)

Reclassification to realized at settlement

667,000

Net mark-to-market gains (losses)

520,000

(88,000)

Exelon Generation Co L L C [Member] | Operating Revenue [Member]

Proprietary Trading Activities [Abstract]

Change in fair value

(12,000)

23,000

26,000

Reclassification to realized at settlement

108,000

(26,000)

(24,000)

Net mark-to-market gains (losses)

96,000

2,000

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

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

2,883,000

1,195,000

Mark-to-market derivative assets with affiliate (current assets)

226,000

Mark-to-market derivative assets (noncurrent assets)

1,792,000

582,000

Total mark-to-market derivative assets

4,901,000

1,777,000

Mark-to-market derivative liabilities (current liabilities)

2,419,000

965,000

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

1,080,000

186,000

Total mark-to-market derivative liabilities

3,499,000

1,151,000

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

1,402,000

626,000

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Current assets collateral offset

113,000

338,000

Noncurrent assets collateral offset

201,000

187,000

Current liabilities collateral offset

(214,000)

15,000

Noncurrent liabilities collateral offset

(131,000)

Total cash collateral received net of cash collateral posted

540,000

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

438,000

Mark-to-market derivative assets with affiliate (current assets)

503,000

Mark-to-market derivative assets (noncurrent assets)

419,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

191,000

Total mark-to-market derivative assets

1,551,000

Mark-to-market derivative liabilities (current liabilities)

9,000

Mark-to-market energy derivative liabilities (noncurrent liabilities)

4,000

Total mark-to-market derivative liabilities

13,000

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

1,538,000

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract current asset

226,000

503,000

Fair value swap contract noncurrent asset

191,000

Noncurrent liability DOE interest rate swap

28,000

19,000

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

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

2,469,000

217,000

Mark-to-market derivative assets (noncurrent assets)

724,000

71,000

Total mark-to-market derivative assets

3,193,000

288,000

Mark-to-market derivative liabilities (current liabilities)

2,432,000

194,000

Mark-to-market energy derivative liabilities (noncurrent liabilities)

689,000

70,000

Total mark-to-market derivative liabilities

3,121,000

264,000

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

72,000

24,000

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

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (current assets)

(4,418,000)

(1,418,000)

Mark-to-market derivative assets (noncurrent assets)

(1,638,000)

(437,000)

Total mark-to-market derivative assets

(6,056,000)

(1,855,000)

Mark-to-market derivative liabilities (current liabilities)

(4,519,000)

(1,065,000)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(1,568,000)

(250,000)

Total mark-to-market derivative liabilities

(6,087,000)

(1,315,000)

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

31,000

(540,000)

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Total cash collateral received net of cash collateral posted

31,000

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Accumulated OCI derivative gain - Beginning Balance

^[2],[3]

925,000

1,011,000

Effective portion of changes in fair value

^[4]

432,000

504,000

Accumulated OCI derivative gain - Ending Balance

^[2],[3]

532,000

925,000

1,011,000

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gain (loss) related to effective portion of changes in fair value of swap contract

88,000

104,000

2,000

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

^[5]

(828,000)

(585,000)

Ineffective portion recognized in income

3,000

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract

375,000

273,000

Net gain (loss) of reclassifications from accumulated OCI to net income related to settlements of block contracts

3,000

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Purchased Power [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Ineffective portion recognized in income

(5,000)

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

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gains (losses) related to interest rate swaps and treasury rate locks

(20,000)

(10,000)

Net gain (loss) related to effective portion of changes in fair value of treasury rate locks

(9,000)

(12,000)

Cash Flow Hedge Activity Impact [Abstract]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

1,368,000

968,000

1,125,000

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

Cash Flow Hedge Activity Impact [Abstract]

Net unrealized pre-tax gain (loss) on effective cash flow hedges

(5,000)

10,000

1,000

Commonwealth Edison Co [Member]

Derivatives Fair Value [Line Items]

Mark-to-market derivative liability with affiliate (current liability)

(226,000)

(503,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

(191,000)

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

Derivatives Fair Value [Line Items]

Mark-to-market derivative liabilities (current liabilities)

18,000

9,000

Mark-to-market derivative liability with affiliate (current liability)

226,000

503,000

Mark-to-market energy derivative liabilities (noncurrent liabilities)

49,000

97,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

191,000

Total mark-to-market derivative liabilities

293,000

800,000

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

(293,000)

(800,000)

Commonwealth Edison Co [Member] | Cash Flow Hedging [Member]

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract current liability

226,000

503,000

Fair value swap contract noncurrent liability

191,000

PECO Energy Co [Member]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Amortization of realized loss on settled cash flow swaps

$ 1,000

Derivatives Fair Value [Line Items]

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

Other Segment [Member] | Designated as Hedging Instrument [Member]

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets (noncurrent assets)

15,000

Total mark-to-market derivative assets

15,000

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

15,000

Other Segment [Member] | Business Intersegment Eliminations [Member]

Derivatives Fair Value [Line Items]

Mark-to-market derivative assets with affiliate (current assets)

(226,000)

(503,000)

Mark-to-market derivative assets with affiliate (noncurrent assets)

(191,000)

Total mark-to-market derivative assets

(226,000)

(694,000)

Mark-to-market derivative liability with affiliate (current liability)

(226,000)

(503,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

(191,000)

Total mark-to-market derivative liabilities

(226,000)

$ (694,000)

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

$ 0

[1]	Includes $9 million and $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2012 and 2011, respectively
[2]	Excludes $20 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2012 and 2011, respectively.
[3]	Includes $133 million, $420 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012, 2011 and 2010, respectively, and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO for the year ended
[4]	Includes $88 million and $104 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $2 million of gains, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended
[5]	Includes $375 million and $273 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $3 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the block contracts with PECO for the year ended

Derivative Financial Instruments (Credit Risk) (Details)
$ in Thousands

Dec. 31, 2012

USD ($)

Exelon Generation Co L L C [Member]

Credit Risk [Abstract]

Financial institutions

$ 422,000

Investor-owned utilities, marketers and power producers

865,000

Energy cooperative and municipalities

786,000

Other

108,000

Total

2,181,000

Due From Related Parties [Abstract]

Net receivable from electric utility

54,000

Net receivable from affiliated electric and gas utility

56,000

Exelon Generation Co L L C [Member] | Total Exposure Before Credit Collateral [Member]

Credit Risk [Abstract]

Investment grade

1,984,000

Non-investment grade

28,000

No external ratings - internally rated - investment grade

512,000

No external ratings - internally rated - non-investment grade

41,000

Total

2,565,000

Exelon Generation Co L L C [Member] | Credit Collateral [Member]

Credit Risk [Abstract]

Investment grade

347,000

^[1]

Non-investment grade

24,000

^[1]

No external ratings - internally rated - investment grade

10,000

^[1]

No external ratings - internally rated - non-investment grade

3,000

^[1]

Total

384,000

^[1]

Exelon Generation Co L L C [Member] | Net Exposure [Member]

Credit Risk [Abstract]

Investment grade

1,637,000

Non-investment grade

4,000

No external ratings - internally rated - investment grade

502,000

No external ratings - internally rated - non-investment grade

38,000

Total

2,181,000

Exelon Generation Co L L C [Member] | Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

Credit Risk [Abstract]

Investment grade

1,000

No external ratings - internally rated - investment grade

1,000

Total

2,000

Exelon Generation Co L L C [Member] | Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

Credit Risk [Abstract]

Investment grade

262,000

No external ratings - internally rated - investment grade

271,000

Total

533,000

Commonwealth Edison Co [Member]

Due From Related Parties [Abstract]

Net receivable from affiliated electric and gas utility

54,000

PECO Energy Co [Member]

Due From Related Parties [Abstract]

Net receivable from affiliated electric and gas utility

56,000

Natural Gas Supply And Management Agreement Credit Exposure [Abstract]

Natural gas asset manager parental guarantee

20,000

Credit exposure under natural gas supply and management agreements

7,000

Baltimore Gas and Electric Company [Member]

Due From Related Parties [Abstract]

Net receivable from affiliated electric and gas utility

31,000

Natural Gas Supply And Management Agreement Credit Exposure [Abstract]

Credit exposure under off system sales

$ 8,000

[1]	As of December 31, 2012, credit collateral held from counterparties where Generation had credit exposure included $344 million of cash and $40 million of letters of credit .

Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Collateral And Contingent Related Features [Abstract]
Line Of Credit Facility Amount Outstanding	$ 1,821,000
Swap Contract Collateral Posting Limit [Abstract]
Fair value of interest-rate swap in asset position	30,000
Exelon Generation Co L L C [Member]
Collateral And Contingent Related Features [Abstract]
Aggregate fair value of derivatives with credit-risk-related contingent features	(1,849,000)	$ (1,014,000)
Contractual right of offset related to derivative assets	1,426,000	928,000
Net liability position after contractual right of offset	(423,000)	(86,000)
Incremental collateral for credit rating downgrade to BBB- and Baa3	1,920,000	1,612,000
Cash collateral held	499,000	542,000
Cash collateral posted	527,000
Letters of credit held	45,000	$ 89,000
Letters of credit posted	563,000
Line Of Credit Facility Amount Outstanding	1,818,000
Swap Contract Collateral Posting Limit [Abstract]
Swap contract collateral posting limit	200,000
Fair value of interest-rate swap in asset position	17,000
Commonwealth Edison Co [Member]
Collateral And Contingent Related Features [Abstract]
Cash collateral held	19,000
Swap Contract Collateral Posting Limit [Abstract]
Swap contract collateral posting limit	200,000
PECO Energy Co [Member]
Collateral And Contingent Related Features [Abstract]
Incremental collateral for loss of investment grade credit rating	35,000
Line Of Credit Facility Amount Outstanding	1,000
Baltimore Gas and Electric Company [Member]
Collateral And Contingent Related Features [Abstract]
Incremental collateral for loss of investment grade credit rating	124,000
Other Segment [Member]
Collateral And Contingent Related Features [Abstract]
Incremental collateral for credit rating downgrade to BBB- and Baa3	$ 1,920,000

Debt and Credit Agreements (Details)
$ in Thousands

9 Months Ended

12 Months Ended

Jun. 28, 2012

USD ($)

Sep. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

CreditAgreementThreshold

BasisPoints

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Jul. 13, 2012

USD ($)

Jun. 18, 2012

USD ($)

Apr. 05, 2012

USD ($)

Credit Agreements [Abstract]

Additional amounts available upon request under current credit facilities

$ 250,000

Letters Of Credit

$ 200,000

Basis Points For Prime Based Borrowings Current | BasisPoints

0.0065

Basis Points For LIBOR Based Borrowings Current | BasisPoints

0.0165

Previous Aggregate Commitments Of Acquired Entity

$ 2,500,000

Amended Aggregate Commitments Of Acquired Entity

1,500,000

Aggregate bank commitments under amendment

500,000

Accounts Receivable Agreement [Abstract]

Accounts receivable, pledged under accounts receivable agreement

225,000

Short-term notes payable - accounts receivable agreement

210,000

$ 225,000

Gross accounts receivable pledged as collateral

$ 289,000

346,000

Debt Covenant [Line Items]

Credit agreement interest coverage minimum threshold | CreditAgreementThreshold

2.50

Interest coverage ratio | CreditAgreementThreshold

9.62

Long-Term Debt [Abstract]

Unsecured Long Term Debt

$ 1,850,000

Total long-term debt

18,297,000

12,644,000

Unamortized debt discount and premium, net

(17,000)

(32,000)

Unamortized settled fair value hedge, net

(448,000)

Fair value hedge carrying value adjustment, net

17,000

15,000

Long-term debt due within one year

(1,047,000)

(828,000)

Long-term debt

17,190,000

11,799,000

Total long-term debt with adjustments

17,698,000

Total long-term debt to financing trusts

^[1]

648,000

390,000

Long-term debt to financing trusts

508,000

390,000

Long Term Debt

18,945,000

Long term debt old notes

258,000

Increase in fair value adjustment

403,000

Fair Value Adjustment Outstanding

199,000

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

8,300,000

Outstanding borrowings/facility draws

1,821,000

Outstanding letters of credit

200,000

Actual available capacity

6,479,000

Available capacity to support additional commercial paper borrowings

6,479,000

Short Term Debt Activity [Line Items]

Average borrowings

199,000

218,000

$ 125,000

Maximum borrowings outstanding

$ 505,000

$ 600,000

$ 346,000

Average interest rates, computed on a daily basis

0.48%

0.50%

0.72%

Average interest rates, at December 31

0.44%

Short Term Debt [Line Items]

Maximum program size

^[3]

$ 8,300,000

$ 8,100,000

Commercial paper borrowings

161,000

ComEd Financing Three Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[1]

$ 206,000

206,000

Interest rate on long-term debt

6.35%

PECO Trust Three Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[1]

$ 81,000

81,000

Interest rate on long-term debt

7.38%

PECO Trust Four Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[1]

$ 103,000

103,000

Interest rate on long-term debt

5.75%

Baltimore Gas Electric Trust [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[1]

$ 258,000

Interest rate on long-term debt

6.20%

Rate Stabilization Bonds, April 1, 2017 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 332,000

Minimum interest rate on long-term debt

5.72%

Maximum interest rate on long-term debt

5.82%

Capital Lease Obligations [Member]

Footnotes To Long-Term Debt [Abstract]

Capital Leases Future Minimum Payments Due Current

$ 3,000

Capital Leases Future Minimum Payments Due In Two Years

3,000

Capital Leases Future Minimum Payments Due In Three Years

3,000

Capital Leases Future Minimum Payments Due In Four Years

4,000

Capital Leases Future Minimum Payments Due In Five Years

4,000

Capital Leases Future Minimum Payments Due Thereafter

13,000

Capital Lease Obligations Noncurrent

30,000

34,000

Notes Payable To Banks [Member]

Long-Term Debt [Abstract]

Long Term Notes Payable

^[4]

$ 177,000

174,000

Interest rate on long-term debt

7.83%

Minimum interest rate on long-term debt

6.95%

Maximum interest rate on long-term debt

7.83%

Senior Notes [Member]

Long-Term Debt [Abstract]

Unsecured Long Term Debt

$ 8,021,000

4,902,000

Minimum interest rate on long-term debt

2.00%

Maximum interest rate on long-term debt

8.63%

First Mortgage Bonds [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Secured Long Term Debt

^[5],[6]

$ 7,397,000

7,522,000

Minimum interest rate on long-term debt

1.63%

Maximum interest rate on long-term debt

7.63%

First Mortgage Bonds [Member] | Floating Rate Debt [Member]

Long-Term Debt [Abstract]

Minimum interest rate on long-term debt

2.80%

Maximum interest rate on long-term debt

6.35%

Pollution Control Notes [Member]

Long-Term Debt [Abstract]

Minimum interest rate on long-term debt

4.10%

Maximum interest rate on long-term debt

5.00%

Pollution Control Notes [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Long Term Pollution Control Bond

$ 20,000

46,000

Non Recourse Debt [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 238,000

Minimum interest rate on long-term debt

2.33%

Maximum interest rate on long-term debt

5.50%

Non Recourse Debt [Member] | Floating Rate Debt [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 262,000

Minimum interest rate on long-term debt

1.96%

Maximum interest rate on long-term debt

2.77%

Long Term Debt Assumed [Member]

Long-Term Debt [Abstract]

Long term debt old notes

$ 608,000

Long Term Debt Assumed [Member] | Fixed Rate Note, 4.55% Due 2015 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 550,000

Interest rate on long-term debt

4.55%

Long Term Debt Assumed [Member] | Series A Junior Subordinated Debentures, 8.625% Due 2063 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 450,000

Interest rate on long-term debt

8.63%

Long Term Debt Assumed [Member] | Notes, 5.15% Due 2020 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 550,000

Interest rate on long-term debt

5.15%

Long Term Debt Exchange Offer Exchanged [Member] | Senior Notes, 7.6% Due 2032 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 700,000

Exelon Corporate [Member]

Credit Agreements [Abstract]

Basis points adders for prime-based borrowings | BasisPoints

0.00275

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01275

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

$ 500,000

Outstanding borrowings/facility draws

2,000

Actual available capacity

498,000

Available capacity to support additional commercial paper borrowings

498,000

Short Term Debt [Line Items]

Maximum program size

^[3]

$ 500,000

500,000

Commercial paper borrowings

$ 161,000

Average Interest Rate On Commercial Paper Borrowings

0.47%

0.42%

Exelon Generation Co L L C [Member]

Credit Agreements [Abstract]

Additional amounts available upon request under current credit facilities

$ 1,000,000

Amount that would constitute an event of default

$ 100,000

Basis points adders for prime-based borrowings | BasisPoints

0.00075

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01075

Letters Of Credit

$ 3,500,000

Bilateral letters of credit

75,000

Aggregate bank commitments under amendment

5,300,000

AVSR Project Development Debt Agreement [Abstract]

DOE loan guarantee

$ 646,000

Basis point spread on DOE loan advance | BasisPoints

0.00375

DOE interest rate swap

$ 485,000

DOE advances received

219,000

$ 69,000

Generation letters of credit outstanding to support project

$ 568,000

Debt Covenant [Line Items]

Credit agreement interest coverage minimum threshold | CreditAgreementThreshold

3.00

Interest coverage ratio | CreditAgreementThreshold

14.20

Long-Term Debt [Abstract]

Long-term debt to affiliate

$ 2,007,000

Total long-term debt

7,271,000

$ 3,682,000

Unamortized debt discount and premium, net

(13,000)

5,000

Long-term debt due within one year

(28,000)

(3,000)

Long-term debt

5,245,000

3,674,000

Total long-term debt with adjustments

7,455,000

3,674,000

Long Term Debt

7,271,000

Fair Value Adjustment Outstanding

^[7]

199,000

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

5,600,000

Outstanding borrowings/facility draws

1,818,000

Outstanding letters of credit

3,500,000

Actual available capacity

3,782,000

Available capacity to support additional commercial paper borrowings

3,782,000

Footnotes To Line Of Credit Facility [Abstract]

Credit facility agreements with minority and community banks

50,000

Letters of credit

23,000

Short Term Debt Activity [Line Items]

Average borrowings

4,000

51,000

Maximum borrowings outstanding

$ 165,000

$ 304,000

Average interest rates, computed on a daily basis

0.45%

0.48%

Short Term Debt [Line Items]

Maximum program size

^[3]

$ 5,600,000

Average Interest Rate On Commercial Paper Borrowings

0.45%

0.48%

Exelon Generation Co L L C [Member] | Capital Lease Obligations [Member]

Footnotes To Long-Term Debt [Abstract]

Capital Leases Future Minimum Payments Due Current

$ 3,000

Capital Leases Future Minimum Payments Due In Two Years

3,000

Capital Leases Future Minimum Payments Due In Three Years

3,000

Capital Leases Future Minimum Payments Due In Four Years

4,000

Capital Leases Future Minimum Payments Due In Five Years

4,000

Capital Leases Future Minimum Payments Due Thereafter

13,000

Capital Lease Obligations Noncurrent

30,000

$ 34,000

Exelon Generation Co L L C [Member] | Notes Payable To Banks [Member]

Long-Term Debt [Abstract]

Long Term Notes Payable

^[4]

30,000

34,000

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

Long-Term Debt [Abstract]

Unsecured Long Term Debt

^[7]

6,721,000

3,602,000

Long-term debt to affiliate

$ 1,808,000

Minimum interest rate on long-term debt

2.00%

Maximum interest rate on long-term debt

8.63%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]

Long-Term Debt [Abstract]

Minimum interest rate on long-term debt

4.10%

Maximum interest rate on long-term debt

5.00%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Long Term Pollution Control Bond

$ 20,000

46,000

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

Long-Term Debt [Abstract]

Minimum interest rate on long-term debt

2.33%

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

Long-Term Debt [Abstract]

Non-recourse debt

$ 38,000

Non-Recourse Debt - MW | MW

Non-Recourse Debt - Term

18 years

Non-Recourse Debt - Interest Rate Swap

$ 29,000

Non-Recourse Debt - Hedge Percentage

75.00%

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

Long-Term Debt [Abstract]

Non-recourse debt

$ 39,000

$ 41,000

Non-Recourse Debt - MW | MW

Non-Recourse Debt - Interest Rate Swap

$ 29,000

Non-Recourse Debt - Hedge Percentage

75.00%

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Secured Solar Credit Lending Agreement [Member]

Long-Term Debt [Abstract]

Non-recourse debt

$ 113,000

Non-Recourse Debt - Term

3 years

Non-Recourse Debt - Commitment

$ 150,000

Non-Recourse Debt - Commitment Increase Available

200,000

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

Long-Term Debt [Abstract]

Non-recourse debt

11,000

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

Long-Term Debt [Abstract]

Non-recourse debt

7,000

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

Long-Term Debt [Abstract]

Non-recourse debt

72,000

Non-Recourse Debt - Commitment

150,000

Non-Recourse Debt - Commitment Increase Available

500,000

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

Long-Term Debt [Abstract]

Long-term debt

$ 238,000

Maximum interest rate on long-term debt

5.50%

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

Long-Term Debt [Abstract]

Long-term debt

$ 262,000

Minimum interest rate on long-term debt

1.96%

Maximum interest rate on long-term debt

2.77%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Senior Notes, 4.25% June 15, 2022 [Member]

Long-Term Debt [Abstract]

Interest rate on long-term debt

4.25%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Senior Notes, 5.6% June 15, 2042 [Member]

Long-Term Debt [Abstract]

Interest rate on long-term debt

5.60%

Exelon Generation Co L L C [Member] | Long Term Debt Assumed [Member]

Long-Term Debt [Abstract]

Increase in fair value adjustment

13,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Issued And Sold [Member]

Footnotes To Long-Term Debt [Abstract]

Notional amount of interest rate cash flow hedge derivatives

$ 470,000

Loss on interest rate swap

7,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Issued And Sold [Member] | Senior Notes [Member]

Long-Term Debt [Abstract]

Long Term Debt

$ 775,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Purchased [Member]

Long-Term Debt [Abstract]

Long-term debt

441,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Exchanged [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 1,000

Long Term Debt

535,000

Cash payment related to exchange offer

$ 60,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Exchanged [Member] | Senior Notes, 7.6% Due 2032 [Member]

Long-Term Debt [Abstract]

Interest rate on long-term debt

7.60%

Commonwealth Edison Co [Member]

Credit Agreements [Abstract]

Additional amounts available upon request under current credit facilities

$ 500,000

Letters Of Credit

500,000

Aggregate bank commitments under amendment

$ 1,000,000

Debt Covenant [Line Items]

Credit agreement interest coverage minimum threshold | CreditAgreementThreshold

2.00

Interest coverage ratio | CreditAgreementThreshold

6.14

Long-Term Debt [Abstract]

Total long-term debt

$ 5,587,000

$ 5,687,000

Unamortized debt discount and premium, net

20,000

22,000

Unamortized settled fair value hedge, net

Long-term debt due within one year

(252,000)

(450,000)

Long-term debt

5,315,000

5,215,000

Long-term debt to financing trusts

206,000

Long Term Debt

5,793,000

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

1,000,000

Outstanding letters of credit

500,000

Actual available capacity

1,000,000

Available capacity to support additional commercial paper borrowings

1,000,000

Footnotes To Line Of Credit Facility [Abstract]

Credit facility agreements with minority and community banks

34,000

Letters of credit

21,000

Short Term Debt Activity [Line Items]

Average borrowings

110,000

36,000

$ 125,000

Maximum borrowings outstanding

$ 366,000

$ 407,000

$ 346,000

Average interest rates, computed on a daily basis

0.50%

0.71%

0.72%

Short Term Debt [Line Items]

Maximum program size

^[3]

$ 1,000,000

Average Interest Rate On Commercial Paper Borrowings

0.71%

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[8]

$ 206,000

Interest rate on long-term debt

6.35%

Commonwealth Edison Co [Member] | Notes Payable To Banks [Member]

Long-Term Debt [Abstract]

Long Term Notes Payable

$ 140,000

140,000

Interest rate on long-term debt

6.95%

Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Secured Long Term Debt

^[9],[10]

$ 5,447,000

5,547,000

Minimum interest rate on long-term debt

1.63%

Maximum interest rate on long-term debt

7.63%

PECO Energy Co [Member]

Credit Agreements [Abstract]

Additional amounts available upon request under current credit facilities

$ 250,000

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01

Letters Of Credit

$ 300,000

Aggregate bank commitments under amendment

600,000

Accounts Receivable Agreement [Abstract]

Accounts receivable, pledged under accounts receivable agreement

225,000

Short-term notes payable - accounts receivable agreement

210,000

225,000

Accounts receivable, principal payment

15,000

Gross accounts receivable pledged as collateral

$ 289,000

329,000

Debt Covenant [Line Items]

Credit agreement interest coverage minimum threshold | CreditAgreementThreshold

2.00

Interest coverage ratio | CreditAgreementThreshold

7.85

Long-Term Debt [Abstract]

Total long-term debt

$ 1,647,000

1,597,000

Unamortized debt discount and premium, net

3,000

Long-term debt due within one year

(300,000)

(375,000)

Long-term debt

1,647,000

1,597,000

Long-term debt to PECO Energy Transition Trust due within one year

Total long-term debt to financing trusts

^[11]

184,000

Long-term debt to financing trusts

184,000

Long Term Debt

2,134,000

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

600,000

Outstanding borrowings/facility draws

1,000

Outstanding letters of credit

300,000

Actual available capacity

599,000

Available capacity to support additional commercial paper borrowings

599,000

Footnotes To Line Of Credit Facility [Abstract]

Credit facility agreements with minority and community banks

34,000

Letters of credit

21,000

Short Term Debt [Line Items]

Maximum program size

^[3]

600,000

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[11]

$ 81,000

81,000

Interest rate on long-term debt

7.38%

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

Long-Term Debt [Abstract]

Long-term debt to financing trusts

^[11]

$ 103,000

103,000

Interest rate on long-term debt

5.75%

PECO Energy Co [Member] | First Mortgage Bonds [Member]

Long-Term Debt [Abstract]

Maximum interest rate on long-term debt

5.95%

PECO Energy Co [Member] | First Mortgage Bonds [Member] | Fixed Rate Debt [Member]

Long-Term Debt [Abstract]

Long-term debt

^[12],[13]

$ 1,950,000

1,975,000

Minimum interest rate on long-term debt

2.38%

Baltimore Gas and Electric Company [Member]

Credit Agreements [Abstract]

Additional amounts available upon request under current credit facilities

$ 100,000

Basis points adders for prime-based borrowings | BasisPoints

0.00075

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01075

Letters Of Credit

$ 600,000

Aggregate bank commitments under amendment

$ 600,000

Debt Covenant [Line Items]

Credit agreement interest coverage minimum threshold | CreditAgreementThreshold

2.00

Interest coverage ratio | CreditAgreementThreshold

5.16

Long-Term Debt [Abstract]

Unsecured Long Term Debt

$ 1,850,000

1,710,000

Total long-term debt

2,182,000

2,105,000

Unamortized debt discount and premium, net

4,000

Long-term debt due within one year

(467,000)

(173,000)

Long-term debt

1,446,000

1,596,000

Total long-term debt with adjustments

1,711,000

1,928,000

Long-term debt to financing trusts

$ 258,000

258,000

Minimum interest rate on long-term debt

2.80%

Maximum interest rate on long-term debt

6.35%

Long Term Debt

$ 2,440,000

Line Of Credit Facility [Abstract]

Aggregate bank commitments under unsecured revolving credit facilities

^[2]

600,000

Outstanding letters of credit

600,000

Actual available capacity

600,000

Available capacity to support additional commercial paper borrowings

600,000

Footnotes To Line Of Credit Facility [Abstract]

Credit facility agreements with minority and community banks

5,000

Letters of credit

1,000

Short Term Debt Activity [Line Items]

Average borrowings

6,000

26,000

$ 1,000

Maximum borrowings outstanding

$ 76,000

$ 190,000

$ 46,000

Average interest rates, computed on a daily basis

0.43%

0.38%

0.39%

Short Term Debt [Line Items]

Maximum program size

^[3]

$ 600,000

$ 400,000

Average Interest Rate On Commercial Paper Borrowings

0.43%

0.38%

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

Long-Term Debt [Abstract]

Total long-term debt to financing trusts

^[14]

$ 258,000

Long-term debt to financing trusts

^[14]

$ 258,000

258,000

Interest rate on long-term debt

6.20%

Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds, April 1, 2017 [Member]

Long-Term Debt [Abstract]

Long-term debt

$ 332,000

$ 395,000

Minimum interest rate on long-term debt

5.47%

Maximum interest rate on long-term debt

5.82%

[1]	Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets.
[2]	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd's, PECO's and BGE’s service territories. These facilities expire on October 19, 2013 and are solely for issuing letters of credit. As of December 31, 2012, letters of credit issued under these agreements totaled $23 million, $21 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively.
[3]	(a) Equals aggregate bank commitments under revolving and bilateral credit agreements. See discussion below and Credit Agreements table below for items affecting effective program size.
[4]	Includes capital lease obligations of $30 million and $34 million at December 31, 2012 and 2011, respectively. Lease payments of $3 million, $3 million, $3 million, $4 million, $4 million and $13 million will be made in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.
[5]	Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.
[6]	Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures.
[7]	Includes $2,007 million of long-term debt to affiliate, comprised of $1,808 million senior unsecured notes and $199 million fair value adjustment.
[8]	Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets.
[9]	Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.
[10]	Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture.
[11]	Amount owed to this financing trust is recorded as debt to financing trust within PECO's Consolidated Balance Sheets.
[12]	Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.
[13]	Substantially all of PECO's assets are subject to the lien of its mortgage indenture.
[14]	(a) Amount owed to this financing trust is recorded as debt to financing trust within BGE's Consolidated Balance Sheets.

Debt and Credit Agreements (Maturitites of Long-term Debt) (Details)
$ in Thousands

Dec. 31, 2012

USD ($)

Long Term Debt By Maturity [Abstract]

Long Term Debt Maturities Repayments Of Principal In Next Twelve Months

$ 979,000

Long Term Debt Maturities Repayments Of Principal In Year Two

1,483,000

Long Term Debt Maturities Repayments Of Principal In Year Three

1,613,000

Long Term Debt Maturities Repayments Of Principal In Year Four

1,041,000

Long Term Debt Maturities Repayments Of Principal In Year Five

1,462,000

Long Term Debt Maturities Repayments Of Principal After Year Five

12,367,000

^[1]

Long Term Debt

18,945,000

Exelon Generation Co L L C [Member]

Long Term Debt By Maturity [Abstract]

Long Term Debt Maturities Repayments Of Principal In Next Twelve Months

28,000

Long Term Debt Maturities Repayments Of Principal In Year Two

616,000

Long Term Debt Maturities Repayments Of Principal In Year Three

553,000

Long Term Debt Maturities Repayments Of Principal In Year Four

76,000

Long Term Debt Maturities Repayments Of Principal In Year Five

706,000

Long Term Debt Maturities Repayments Of Principal After Year Five

5,292,000

Long Term Debt

7,271,000

Commonwealth Edison Co [Member]

Long Term Debt By Maturity [Abstract]

Long Term Debt Maturities Repayments Of Principal In Next Twelve Months

252,000

Long Term Debt Maturities Repayments Of Principal In Year Two

617,000

Long Term Debt Maturities Repayments Of Principal In Year Three

260,000

Long Term Debt Maturities Repayments Of Principal In Year Four

665,000

Long Term Debt Maturities Repayments Of Principal In Year Five

425,000

Long Term Debt Maturities Repayments Of Principal After Year Five

3,574,000

^[2]

Long Term Debt

5,793,000

PECO Energy Co [Member]

Long Term Debt By Maturity [Abstract]

Long Term Debt Maturities Repayments Of Principal In Next Twelve Months

300,000

Long Term Debt Maturities Repayments Of Principal In Year Two

250,000

Long Term Debt Maturities Repayments Of Principal In Year Three

Long Term Debt Maturities Repayments Of Principal In Year Four

Long Term Debt Maturities Repayments Of Principal In Year Five

Long Term Debt Maturities Repayments Of Principal After Year Five

1,584,000

^[3]

Long Term Debt

2,134,000

Baltimore Gas and Electric Company [Member]

Long Term Debt By Maturity [Abstract]

Long Term Debt Maturities Repayments Of Principal In Next Twelve Months

467,000

Long Term Debt Maturities Repayments Of Principal In Year Two

70,000

Long Term Debt Maturities Repayments Of Principal In Year Three

75,000

Long Term Debt Maturities Repayments Of Principal In Year Four

379,000

Long Term Debt Maturities Repayments Of Principal In Year Five

41,000

Long Term Debt Maturities Repayments Of Principal After Year Five

1,408,000

^[4]

Long Term Debt

$ 2,440,000

[1]	) Includes $648 million due to ComEd, PECO and BGE financing trusts.
[2]	Includes $206 million due to ComEd financing trust.
[3]	Includes $184 million due to PECO financing trusts.
[4]	Includes $258 million due to BGE financing trust.

Income Taxes (Details) - USD ($)
$ in Thousands

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2012

Mar. 31, 2012

Mar. 31, 2011

Sep. 30, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Effective Income Tax Rate Reconciliation

U.S. Federal statutory rate

35.00%

^[1]

35.00%

Increase (decrease) due to:

State income taxes, net of Federal income tax benefit

(3.60%)

^[1]

4.40%

3.00%

Qualified nuclear decommissioning trust fund income (losses)

5.40%

^[1]

0.50%

1.70%

Domestic production activities deduction

(0.30%)

(1.20%)

Tax exempt income

(0.20%)

^[1]

(0.20%)

(0.10%)

Nontaxable postretirement benefits

(0.30%)

Health Care Reform Legislation

0.10%

^[1]

(0.20%)

1.40%

Amortization of investment tax credit

(1.10%)

^[1]

0.90%

(0.30%)

Plant basis differences

(2.40%)

^[1]

(1.00%)

Production Tax Credits

^[1]

(2.20%)

Fines and Penalties

^[1]

(2.60%)

Merger Expenses

^[1],[2]

(2.40%)

Other

(1.10%)

^[1]

(0.20%)

Effective income tax rate

34.90%

^[1]

36.80%

39.30%

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

Tax positions for which there is uncertainty about the timing of tax benefits

$ 730,000

$ 804,000

Accounting for Uncertainty in Income Taxes [Abstract]

Unrecognized tax benefits that if recognized would affect the effective tax rate

294,000

3,000

Interest recognized related to uncertain tax positions [Abstract]

Net interest receivable (payable) recognized related to uncertain tax positions

31,000

74,000

Net interest (income) expense recognized related to uncertain tax positions

(1,000)

(56,000)

$ 110,000

Tax Method of Accounting for Repairs [Abstract]

Repair cost tax benefit

$ 26,000

1999 Sale of Fossil Generating Assets [Abstract]

Deferred tax gain on sale of fossil generating assets

2,800,000

Deferred tax gain under involuntary conversion provisions of the IRC

1,600,000

Deferred tax gain under like-kind exchange provisions of the IRC

1,200,000

IRS asserted penalties for understatement of tax

86,000

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

860,000

Potential interest expense from a successful IRS challenge of the like-kind exchange position

320,000

Unsuccessful Litigation Determinations [Abstract]

Expected non-cash charge to earnings

270,000

Unrecognized tax benefits for Generation Repairs

107,000

FIN 48 Tax Remeasurement [Abstract]

FIN 48 Tax Remeasurement Interest Expense

65,000

Tax Settlement [Abstract]

Payment to IRS for open tax positions

302,000

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Income tax benefit recorded as a result of re-apportionment of state income taxes

3,000

$ 116,000

$ 22,000

1,000

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

72,000

Deferred state tax liability resulting from purchase accounting

44,000

Income and cash tax benefit as a result of repair costs deduction [Abstract]

Cash tax benefit (detriment) as a result of repair costs deduction

300,000

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward]

Unrecognized tax benefits - beginning balance

807,000

787,000

807,000

787,000

1,498,000

Merger Balance Transfer

195,000

Increases based on tax positions related to current year

34,000

5,000

1,000

Decreases based on tax positions related to current year

(2,000)

Changes to tax positions that only affect timing

(88,000)

21,000

(262,000)

Increases based on tax positions prior to current year

(91,000)

8,000

Decreases based on tax positions prior to current year

6,000

(3,000)

3,000

2,000

(452,000)

Decreases from expiration of statute of limitations

(7,000)

(3,000)

(1,000)

Unrecognized tax benefits - ending balance

1,024,000

807,000

787,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Income Tax Expense (Benefit)

627,000

1,457,000

1,658,000

Operating Loss Carryforwards [Line Items]

Federal net operating loss

^[3]

635,000

Federal capital loss carryforward

^[4]

178,000

Federal general business credits carryforward

^[5]

226,000

State net operating loss carryforward

^[6]

3,365,000

State capital loss carryforward

^[7]

127,000

Deferred taxes

187,000

Valuation allowance

36,000

Tax Effects Of Temporary Differences [Line Items]

Plant basis differences

(10,689,000)

(7,803,000)

Accrual based contracts

(389,000)

Unrealized gains on derivative financial instruments

(392,000)

(468,000)

Deferred pension and other post-retirement obligation

1,225,000

665,000

Nuclear decommissioning activities

(604,000)

(452,000)

Deferred debt refinancing costs

(537,000)

(37,000)

Net operating losses

421,000

Tax credit carry-forward

226,000

Investment in CENG

(405,000)

Other, net

(25,000)

41,000

Deferred income tax liabilities, net

(11,169,000)

(8,054,000)

Unamortized investment tax credits

(251,000)

(200,000)

Total deferred income tax liabilities, net and unamortized investment tax credits

(11,420,000)

(8,254,000)

Federal Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

37,000

1,000

506,000

Deferred Income Tax Expense Benefit

701,000

1,200,000

972,000

Investment tax credit amortization

(11,000)

(12,000)

State Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

(25,000)

(3,000)

171,000

Deferred Income Tax Expense Benefit

$ (75,000)

$ 271,000

$ 21,000

Exelon Generation Co L L C [Member]

Effective Income Tax Rate Reconciliation

U.S. Federal statutory rate

35.00%

^[1]

35.00%

Increase (decrease) due to:

State income taxes, net of Federal income tax benefit

4.70%

^[1]

4.50%

3.70%

Qualified nuclear decommissioning trust fund income (losses)

9.10%

^[1]

0.70%

2.30%

Domestic production activities deduction

(0.40%)

(1.50%)

Tax exempt income

(0.40%)

^[1]

(0.20%)

Nontaxable postretirement benefits

(0.30%)

Health Care Reform Legislation

0.70%

Amortization of investment tax credit

(1.30%)

^[1]

1.20%

(0.20%)

Production Tax Credits

^[1]

(3.70%)

Uncertain Tax Position Remeasurement

(2.00%)

Fines and Penalties

^[1]

(4.40%)

Other

(0.50%)

^[1]

(0.70%)

(0.40%)

Effective income tax rate

47.30%

^[1]

37.40%

Accounting for Uncertainty in Income Taxes [Abstract]

Unrecognized tax benefits that if recognized would affect the effective tax rate

263,000

$ 263,000

$ 3,000

Information by nature of uncertainty related to unrecognized tax benefits

100,000

Interest recognized related to uncertain tax positions [Abstract]

Net interest receivable (payable) recognized related to uncertain tax positions

(20,000)

33,000

Net interest (income) expense recognized related to uncertain tax positions

11,000

(40,000)

$ 6,000

FIN 48 Tax Remeasurement [Abstract]

FIN 48 Tax Remeasurement Current Tax Expense (Benefit)

(70,000)

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Income tax benefit recorded as a result of re-apportionment of state income taxes

7,000

14,000

11,000

8,000

Deferred state tax liability resulting from purchase accounting

14,000

Income and cash tax benefit as a result of repair costs deduction [Abstract]

Income tax benefit (expense) as a result of repair costs deduction

28,000

Cash tax benefit (detriment) as a result of repair costs deduction

28,000

Allocated tax benefits [Abstract]

Allocated tax benefits

48,000

30,000

60,000

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward]

Unrecognized tax benefits - beginning balance

683,000

664,000

683,000

664,000

633,000

Merger Balance Transfer

183,000

Increases based on tax positions related to current year

3,000

1,000

Decreases based on tax positions related to current year

(2,000)

Changes to tax positions that only affect timing

(69,000)

24,000

55,000

Increases based on tax positions prior to current year

(91,000)

8,000

Decreases based on tax positions prior to current year

6,000

(3,000)

3,000

2,000

(26,000)

Decreases from expiration of statute of limitations

(7,000)

(3,000)

(1,000)

Unrecognized tax benefits - ending balance

876,000

683,000

664,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Income Tax Expense (Benefit)

500,000

1,056,000

1,178,000

Operating Loss Carryforwards [Line Items]

Federal net operating loss

303,000

Federal capital loss carryforward

178,000

Federal general business credits carryforward

226,000

State net operating loss carryforward

^[8]

1,649,000

State capital loss carryforward

^[9]

119,000

Deferred taxes

99,000

Valuation allowance

35,000

Tax Effects Of Temporary Differences [Line Items]

Plant basis differences

(3,545,000)

(2,670,000)

Accrual based contracts

(389,000)

Unrealized gains on derivative financial instruments

(479,000)

(737,000)

Deferred pension and other post-retirement obligation

(439,000)

(520,000)

Nuclear decommissioning activities

(604,000)

(452,000)

Deferred debt refinancing costs

163,000

Net operating losses

226,000

Tax credit carry-forward

226,000

Investment in CENG

(419,000)

Other, net

9,000

338,000

Deferred income tax liabilities, net

(5,251,000)

(4,041,000)

Unamortized investment tax credits

(216,000)

(169,000)

Total deferred income tax liabilities, net and unamortized investment tax credits

(5,467,000)

(4,210,000)

Exelon Generation Co L L C [Member] | Settlement With Taxing Authority [Member]

Accounting for Uncertainty in Income Taxes [Abstract]

Information by nature of uncertainty related to unrecognized tax benefits

55,000

Exelon Generation Co L L C [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

104,000

431,000

372,000

Deferred Income Tax Expense Benefit

326,000

435,000

635,000

Investment tax credit amortization

(6,000)

(7,000)

Exelon Generation Co L L C [Member] | State Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

(12,000)

74,000

65,000

Deferred Income Tax Expense Benefit

$ 88,000

$ 123,000

$ 113,000

Commonwealth Edison Co [Member]

Effective Income Tax Rate Reconciliation

U.S. Federal statutory rate

35.00%

Increase (decrease) due to:

State income taxes, net of Federal income tax benefit

4.60%

3.60%

6.30%

Nontaxable postretirement benefits

(0.40%)

Health Care Reform Legislation

0.40%

(1.00%)

1.40%

Amortization of investment tax credit

(0.40%)

Plant basis differences

(0.30%)

(0.10%)

Uncertain Tax Position Remeasurement

9.00%

Other

(0.60%)

0.60%

0.20%

Effective income tax rate

38.70%

37.50%

51.40%

Interest recognized related to uncertain tax positions [Abstract]

Net interest receivable (payable) recognized related to uncertain tax positions

107,000

$ 107,000

$ 23,000

Net interest (income) expense recognized related to uncertain tax positions

(20,000)

(14,000)

$ 57,000

Unsuccessful Litigation Determinations [Abstract]

Expected non-cash charge to earnings

185,000

FIN 48 Tax Remeasurement [Abstract]

FIN 48 Tax Remeasurement Interest Expense

36,000

FIN 48 Tax Remeasurement Current Tax Expense (Benefit)

70,000

Income and cash tax benefit as a result of repair costs deduction [Abstract]

Cash tax benefit (detriment) as a result of repair costs deduction

250,000

Allocated tax benefits [Abstract]

Allocated tax benefits

2,000

Intercompany Non-Cash Allocation of Tax Benefit

11,000

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward]

Unrecognized tax benefits - beginning balance

70,000

72,000

70,000

72,000

471,000

Changes to tax positions that only affect timing

(3,000)

(2,000)

(3,000)

(396,000)

Unrecognized tax benefits - ending balance

67,000

70,000

72,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Income Tax Expense (Benefit)

239,000

250,000

357,000

Operating Loss Carryforwards [Line Items]

Federal net operating loss

91,000

Tax Effects Of Temporary Differences [Line Items]

Plant basis differences

(3,537,000)

(3,264,000)

Unrealized gains on derivative financial instruments

(4,000)

Deferred pension and other post-retirement obligation

(598,000)

(623,000)

Deferred debt refinancing costs

(25,000)

(31,000)

Net operating losses

32,000

Other, net

(33,000)

16,000

Deferred income tax liabilities, net

(4,165,000)

(3,906,000)

Unamortized investment tax credits

(24,000)

(26,000)

Total deferred income tax liabilities, net and unamortized investment tax credits

(4,189,000)

(3,932,000)

Commonwealth Edison Co [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

(40,000)

(329,000)

(203,000)

Deferred Income Tax Expense Benefit

237,000

544,000

496,000

Investment tax credit amortization

(2,000)

(3,000)

Commonwealth Edison Co [Member] | State Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

6,000

(123,000)

(22,000)

Deferred Income Tax Expense Benefit

$ 38,000

$ 161,000

$ 89,000

PECO Energy Co [Member]

Effective Income Tax Rate Reconciliation

U.S. Federal statutory rate

35.00%

Increase (decrease) due to:

State income taxes, net of Federal income tax benefit

2.00%

(0.50%)

(4.70%)

Nontaxable postretirement benefits

(0.30%)

Health Care Reform Legislation

1.60%

Amortization of investment tax credit

(0.30%)

(0.40%)

Plant basis differences

(11.50%)

(6.90%)

0.20%

Other

(0.20%)

0.20%

Effective income tax rate

25.00%

27.30%

31.90%

Interest recognized related to uncertain tax positions [Abstract]

Net interest receivable (payable) recognized related to uncertain tax positions

2,000

$ 2,000

$ 28,000

Net interest (income) expense recognized related to uncertain tax positions

(1,000)

$ 35,000

Tax Method of Accounting for Repairs [Abstract]

Repair cost tax benefit

29,000

FIN 48 Tax Remeasurement [Abstract]

FIN 48 Tax Remeasurement Interest Expense

22,000

Income and cash tax benefit as a result of repair costs deduction [Abstract]

Income tax benefit (expense) as a result of repair costs deduction

35,000

Cash tax benefit (detriment) as a result of repair costs deduction

95,000

Allocated tax benefits [Abstract]

Allocated tax benefits

9,000

18,000

43,000

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward]

Unrecognized tax benefits - beginning balance

48,000

44,000

48,000

44,000

372,000

Increases based on tax positions related to current year

4,000

Changes to tax positions that only affect timing

(4,000)

(328,000)

Unrecognized tax benefits - ending balance

44,000

48,000

44,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Income Tax Expense (Benefit)

127,000

146,000

152,000

Operating Loss Carryforwards [Line Items]

State net operating loss carryforward

^[10]

209,000

Deferred taxes

14,000

Tax Effects Of Temporary Differences [Line Items]

Plant basis differences

(2,437,000)

(2,238,000)

Deferred pension and other post-retirement obligation

(11,000)

(31,000)

Deferred debt refinancing costs

(4,000)

(6,000)

Net operating losses

14,000

Other, net

150,000

135,000

Deferred income tax liabilities, net

(2,288,000)

(2,140,000)

Unamortized investment tax credits

(3,000)

(5,000)

Total deferred income tax liabilities, net and unamortized investment tax credits

(2,291,000)

(2,145,000)

PECO Energy Co [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

88,000

(71,000)

464,000

Deferred Income Tax Expense Benefit

25,000

223,000

(276,000)

Investment tax credit amortization

(2,000)

PECO Energy Co [Member] | State Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

4,000

(37,000)

87,000

Deferred Income Tax Expense Benefit

$ 12,000

$ 33,000

$ (121,000)

Baltimore Gas and Electric Company [Member]

Effective Income Tax Rate Reconciliation

U.S. Federal statutory rate

35.00%

^[11]

35.00%

Increase (decrease) due to:

State income taxes, net of Federal income tax benefit

24.30%

^[11]

5.20%

5.50%

Health Care Reform Legislation

11.60%

^[11]

(0.50%)

1.10%

Amortization of investment tax credit

(8.60%)

^[11]

(0.50%)

(0.40%)

Plant basis differences

(9.00%)

^[11]

(2.00%)

(1.00%)

Merger Expenses

^[2],[11]

(24.20%)

Other

(13.90%)

^[11]

(1.70%)

(0.40%)

Effective income tax rate

63.60%

^[11]

35.50%

39.80%

Interest recognized related to uncertain tax positions [Abstract]

Net interest receivable (payable) recognized related to uncertain tax positions

$ (1,000)

Net interest (income) expense recognized related to uncertain tax positions

(3,000)

$ 2,000

Income and cash tax benefit as a result of repair costs deduction [Abstract]

Cash tax benefit (detriment) as a result of repair costs deduction

$ 27,000

Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward]

Unrecognized tax benefits - beginning balance

$ 11,000

$ 73,000

$ 11,000

11,000

73,000

112,000

Merger Balance Transfer

Changes to tax positions that only affect timing

(11,000)

(62,000)

(39,000)

Unrecognized tax benefits - ending balance

11,000

73,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Income Tax Expense (Benefit)

7,000

75,000

97,000

Operating Loss Carryforwards [Line Items]

Federal net operating loss

154,000

State net operating loss carryforward

^[12]

950,000

Deferred taxes

51,000

Valuation allowance

1,000

Tax Effects Of Temporary Differences [Line Items]

Plant basis differences

(1,553,000)

(1,220,000)

Deferred pension and other post-retirement obligation

(12,000)

(93,000)

Deferred debt refinancing costs

(4,000)

Net operating losses

105,000

Other, net

(186,000)

(226,000)

Deferred income tax liabilities, net

(1,650,000)

(1,543,000)

Unamortized investment tax credits

(6,000)

(8,000)

Total deferred income tax liabilities, net and unamortized investment tax credits

$ (1,656,000)

(1,656,000)

(1,551,000)

Baltimore Gas and Electric Company [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

(97,000)

(71,000)

(201,000)

Deferred Income Tax Expense Benefit

101,000

130,000

279,000

Investment tax credit amortization

(1,000)

Baltimore Gas and Electric Company [Member] | State Income Tax Expense Benefit Continuing Operations [Member]

Income Tax Expense Benefit Continuing Operations [Line Items]

Current Income Tax Expense Benefit

(2,000)

Deferred Income Tax Expense Benefit

$ 4,000

$ 17,000

$ 22,000

[1]	Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 - December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012 - December 31, 2012.
[2]	Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.
[3]	Exelon's federal net operating loss will expire beginning in 2033
[4]	Exelon’s federal capital loss carryforwards will expire beginning in 2018
[5]	Exelon’s federal general business credit carryforwards will expire beginning in 2033
[6]	Exelon’s state net operating losses will expire beginning in 2014
[7]	Exelon’s state capital loss carryforwards will expire beginning in 2018
[8]	Generation’s state net operating losses will expire beginning in 2014
[9]	Generation’s state capital loss carryforwards will expire beginning in 2018
[10]	PECO’s state net operating losses will expire beginning in 2032
[11]	BGE activity represents the activity for the twelve months ended December 31, 2012, 2011 and 2010.
[12]	BGE’s state net operating losses will expire beginning in 2026

Asset Retirement Obligation (Details) - USD ($)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Net adjustment to nuclear ARO

$ 1,061,000,000

$ 404,000,000

Resulting pre-tax income (loss) from nuclear ARO adjustment

(10,000,000)

(28,000,000)

Zion Station Decommissioning [Abstract]

Zion Station spent nuclear fuel obligation

79,000,000

65,000,000

ZionSolutions rent payable

EnergySolutions letter of credit

200,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

Current annual decommissioning costs collected

24,000,000

Shortfall of decommissioning funds with recourse

$ 50,000,000

Percent of additional decommissioning shortfall with recourse

5.00%

NDT fund investments

$ 7,248,000,000

$ 6,507,000,000

Percent of NDT funds invested in equity

47.00%

48.00%

Percent of NDT funds invested in fixed income securities

53.00%

52.00%

NRC Minimum Funding Requirements [Abstract]

Assumed annual after-tax return on NDT funds

2.00%

Assumed annual after-tax return on NDT funds for former PECO units

3.00%

Annual average accretion of the ARO

5.00%

Number of years used in present value measurement

30 years

Historical five-year annual average after-tax return on NDT funds

3.60%

Footnotes To Asset Retirement Obligation [Abstract]

Current Portion of ARO

$ 10,000,000

$ 5,000,000

Nuclear Decommissioning Obligation [Line Items]

Pledged assets for Zion Station decommissioning

614,000,000

734,000,000

Total payable to ZionSolutions

^[1]

564,000,000

691,000,000

Current payable to ZionSolutions

^[2]

132,000,000

128,000,000

Zion Station decommissioning costs withdrawn

192,000,000

143,000,000

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

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[3],[4],[5]

386,000,000

(74,000,000)

$ 294,000,000

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[4]

105,000,000

(4,000,000)

104,000,000

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Gains on Zion Station Pledged Assets

$ 73,000,000

48,000,000

Minimum [Member]

NRC Minimum Funding Requirements [Abstract]

Years after cessation of plant operations

10 years

Estimated annual after-tax return on NDT funds

5.30%

Maximum [Member]

NRC Minimum Funding Requirements [Abstract]

Years after cessation of plant operations

70 years

Estimated annual after-tax return on NDT funds

6.20%

Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

$ 3,680,000,000

^[6]

3,276,000,000

Accretion expense

231,000,000

209,000,000

Net increase (decrease) resulting from updates to estimated future cash flows

833,000,000

198,000,000

Costs incurred to decommission retired plants

(3,000,000)

ARO ending balance

4,741,000,000

^[6]

3,680,000,000

^[6]

3,276,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

209,000,000

223,000,000

Development projects

47,000,000

7,000,000

Accretion expense

^[7]

(13,000,000)

(9,000,000)

Net increase (decrease) resulting from updates to estimated future cash flows

^[8]

27,000,000

(24,000,000)

Merger with Constellation

^[9]

58,000,000

Payments

11,000,000

6,000,000

ARO ending balance

343,000,000

209,000,000

223,000,000

Exelon Generation Co L L C [Member]

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Net adjustment to nuclear ARO

1,061,000,000

404,000,000

Resulting pre-tax income (loss) from nuclear ARO adjustment

(10,000,000)

(28,000,000)

Zion Station Decommissioning [Abstract]

Zion Station spent nuclear fuel obligation

79,000,000

65,000,000

ZionSolutions rent payable

EnergySolutions letter of credit

200,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

Current annual decommissioning costs collected

24,000,000

Shortfall of decommissioning funds with recourse

$ 50,000,000

Percent of additional decommissioning shortfall with recourse

5.00%

NDT fund investments

$ 7,248,000,000

$ 6,507,000,000

Percent of NDT funds invested in equity

47.00%

48.00%

Percent of NDT funds invested in fixed income securities

53.00%

52.00%

NRC Minimum Funding Requirements [Abstract]

Assumed annual after-tax return on NDT funds

2.00%

Assumed annual after-tax return on NDT funds for former PECO units

3.00%

Annual average accretion of the ARO

5.00%

Number of years used in present value measurement

30 years

Historical five-year annual average after-tax return on NDT funds

3.60%

NRC funding assurance parent guarantees

$ 115,000,000

Footnotes To Asset Retirement Obligation [Abstract]

Current Portion of ARO

10,000,000

$ 5,000,000

Reduction to operating and maintenance expense due to updates to estimated future cash flows

8,000,000

Nuclear Decommissioning Obligation [Line Items]

Pledged assets for Zion Station decommissioning

614,000,000

734,000,000

Total payable to ZionSolutions

^[1]

564,000,000

691,000,000

Current payable to ZionSolutions

^[2]

132,000,000

128,000,000

Zion Station decommissioning costs withdrawn

192,000,000

143,000,000

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

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[3],[4],[5]

386,000,000

(74,000,000)

294,000,000

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[4]

105,000,000

(4,000,000)

104,000,000

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Gains on Zion Station Pledged Assets

$ 73,000,000

48,000,000

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

NRC Minimum Funding Requirements [Abstract]

Years after cessation of plant operations

10 years

Estimated annual after-tax return on NDT funds

5.30%

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

NRC Minimum Funding Requirements [Abstract]

Years after cessation of plant operations

70 years

Estimated annual after-tax return on NDT funds

6.20%

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

$ 3,680,000,000

^[6]

3,276,000,000

Accretion expense

231,000,000

209,000,000

Net increase (decrease) resulting from updates to estimated future cash flows

833,000,000

198,000,000

Costs incurred to decommission retired plants

(3,000,000)

ARO ending balance

4,741,000,000

^[6]

3,680,000,000

^[6]

3,276,000,000

Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

92,000,000

86,000,000

Development projects

47,000,000

7,000,000

Accretion expense

^[7]

(8,000,000)

(5,000,000)

Net increase (decrease) resulting from updates to estimated future cash flows

^[8]

18,000,000

(3,000,000)

Merger with Constellation

^[9]

50,000,000

Payments

8,000,000

3,000,000

ARO ending balance

207,000,000

92,000,000

86,000,000

Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

89,000,000

105,000,000

Accretion expense

^[7]

(4,000,000)

(3,000,000)

Net increase (decrease) resulting from updates to estimated future cash flows

^[8]

8,000,000

(17,000,000)

Payments

2,000,000

ARO ending balance

99,000,000

89,000,000

105,000,000

PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

28,000,000

32,000,000

Accretion expense

^[7]

(1,000,000)

Net increase (decrease) resulting from updates to estimated future cash flows

^[8]

1,000,000

(4,000,000)

Payments

1,000,000

ARO ending balance

29,000,000

28,000,000

32,000,000

Footnotes To Asset Retirement Obligation [Abstract]

Reduction to operating and maintenance expense due to updates to estimated future cash flows

3,000,000

Baltimore Gas and Electric Company [Member]

Footnotes To Asset Retirement Obligation [Abstract]

BGE ARO costs incurred prior to merger

8,000,000

Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

1,000,000

Net increase (decrease) resulting from updates to estimated future cash flows

^[8]

7,000,000

ARO ending balance

$ 8,000,000

$ 1,000,000

[1]	Excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in other current liabilities within Generation’s Consolidated Balance Sheets.
[3]	Excludes $73 million and $48 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2012 and 2011. 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.
[4]	Net unrealized gains (losses) related to Generation's NDT funds are included within other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
[5]	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.
[6]	Includes $10 million and $5 million as the current portion of the ARO at December 31, 2012 and 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.
[7]	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
[8]	During the year ended December 31, 2011, PECO recorded a reduction in operating and maintenance expense of $3 million. Generation and ComEd did not record any reductions in operating and maintenance expense for the year ended December 31, 2011. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2012.
[9]	Exelon’s ARO includes $8 million of BGE costs incurred prior to the closing of Exelon’s merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information.

Nuclear Decommissioning (Details) - USD ($)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Footnotes To Asset Retirement Obligation [Abstract]

Current Portion of ARO

$ 10,000,000

$ 5,000,000

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Net adjustment to nuclear ARO

1,061,000,000

404,000,000

Resulting pre-tax income (loss) from nuclear ARO adjustment

(10,000,000)

(28,000,000)

Nuclear Decommissioning Trust Fund Investments [Abstract]

NDT fund investments

7,248,000,000

6,507,000,000

Zion Station Decommissioning [Abstract]

Zion Station spent nuclear fuel obligation

79,000,000

65,000,000

Pledged assets for Zion Station decommissioning

614,000,000

734,000,000

Total payable to ZionSolutions

^[1]

564,000,000

691,000,000

Current payable to ZionSolutions

^[2]

132,000,000

128,000,000

Zion Station decommissioning costs withdrawn

192,000,000

143,000,000

ZionSolutions rent payable

EnergySolutions letter of credit

$ 200,000,000

NRC Minimum Funding Requirements [Abstract]

Assumed annual after-tax return on NDT funds

2.00%

Assumed annual after-tax return on NDT funds for former PECO units

3.00%

Annual average accretion of the ARO

5.00%

Historical five-year annual average after-tax return on NDT funds

3.60%

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

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[3],[4],[5]

$ 386,000,000

(74,000,000)

$ 294,000,000

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[4]

105,000,000

(4,000,000)

104,000,000

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Gains on Zion Station Pledged Assets

73,000,000

48,000,000

Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

3,680,000,000

^[6]

3,276,000,000

Accretion expense

231,000,000

209,000,000

Net increase (decrease) resulting from updates to estimated future cash flows

833,000,000

198,000,000

Costs incurred to decommission retired plants

(3,000,000)

ARO ending balance

4,741,000,000

^[6]

3,680,000,000

^[6]

3,276,000,000

Exelon Generation Co L L C [Member]

Footnotes To Asset Retirement Obligation [Abstract]

Current Portion of ARO

10,000,000

5,000,000

Reduction to operating and maintenance expense due to updates to estimated future cash flows

8,000,000

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Net adjustment to nuclear ARO

1,061,000,000

404,000,000

Resulting pre-tax income (loss) from nuclear ARO adjustment

(10,000,000)

(28,000,000)

Nuclear Decommissioning Trust Fund Investments [Abstract]

NDT fund investments

7,248,000,000

6,507,000,000

Zion Station Decommissioning [Abstract]

Zion Station spent nuclear fuel obligation

79,000,000

65,000,000

Pledged assets for Zion Station decommissioning

614,000,000

734,000,000

Total payable to ZionSolutions

^[1]

564,000,000

691,000,000

Current payable to ZionSolutions

^[2]

132,000,000

128,000,000

Zion Station decommissioning costs withdrawn

192,000,000

143,000,000

ZionSolutions rent payable

EnergySolutions letter of credit

$ 200,000,000

NRC Minimum Funding Requirements [Abstract]

Assumed annual after-tax return on NDT funds

2.00%

Assumed annual after-tax return on NDT funds for former PECO units

3.00%

Annual average accretion of the ARO

5.00%

Historical five-year annual average after-tax return on NDT funds

3.60%

NRC funding assurance parent guarantees

$ 115,000,000

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

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[3],[4],[5]

386,000,000

(74,000,000)

294,000,000

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[4]

105,000,000

(4,000,000)

104,000,000

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Gains on Zion Station Pledged Assets

73,000,000

48,000,000

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

ARO beginning balance

3,680,000,000

^[6]

3,276,000,000

Accretion expense

231,000,000

209,000,000

Net increase (decrease) resulting from updates to estimated future cash flows

833,000,000

198,000,000

Costs incurred to decommission retired plants

(3,000,000)

ARO ending balance

$ 4,741,000,000

^[6]

$ 3,680,000,000

^[6]

$ 3,276,000,000

[1]	Excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in other current liabilities within Generation’s Consolidated Balance Sheets.
[3]	Excludes $73 million and $48 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2012 and 2011. 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.
[4]	Net unrealized gains (losses) related to Generation's NDT funds are included within other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
[5]	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.
[6]	Includes $10 million and $5 million as the current portion of the ARO at December 31, 2012 and 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Retirement Benefits (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Defined Benefit Plan Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Abstract]

Effect of a one percentage point increase in assumed healthcare cost trend on 2010 total service and interest cost components

$ 81,000

Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010

845,000

Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components

56,000

Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010

569,000

Change in benefit obligation:

Acquisitions/divestitures

362,000

Settlements

(169,000)

Reinsurance proceeds received

1,300

Change in plan assets:

Benefits paid net

$ (189,000)

Settlements

(169,000)

Prescription Drug Benefit Effect Of Subsidy On Net Periodic Postretirement Benefit Cost [Abstract]

Amortization of the actuarial experience loss

(17,000)

3,000

$ 9,000

Reduction in current period service cost

9,000

10,000

Reduction in interest cost on the APBO

16,000

19,000

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

(17,000)

28,000

38,000

Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:

Settlements

(31,000)

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

462,000

2,360,000

959,000

Federal subsidy payments received not included in contributions

10,000

11,000

10,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

$ 820,000

$ 542,000

581,000

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

32.00%

Total weighted average asset allocation

40.00%

Defined Contribution Plan Contributions By Employer [Abstract]

Savings plan matching contributions

$ 67,000

$ 78,000

81,000

Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plan Pension Plans With Accumulated Benefit Obligations In Excess Of Plan Assets [Abstract]

Projected benefit obligation

16,800,000

13,538,000

Fair value of net plan assets

13,357,000

11,302,000

Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plan Pension Plans With Accumulated Benefit Obligations In Excess Of Plan Assets [Abstract]

Projected benefit obligation

16,796,000

13,538,000

Accumulated benefit obligation

15,657,000

12,616,000

Fair value of net plan assets

$ 13,353,000

$ 11,302,000

Equity Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Total weighted average asset allocation

37.00%

Fixed Income Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Total weighted average asset allocation

40.00%

53.00%

Alternative Investments [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Total weighted average asset allocation

14.00%

10.00%

Business Services Company [Member]

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

^[1]

$ 99,000

$ 48,000

52,000

Exelon Generation Co L L C [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

178,000

1,070,000

445,000

Federal subsidy payments received not included in contributions

5,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

341,000

249,000

268,000

Defined Contribution Plan Contributions By Employer [Abstract]

Savings plan matching contributions

30,000

40,000

42,000

Commonwealth Edison Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

138,000

977,000

317,000

Federal subsidy payments received not included in contributions

4,000

3,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

282,000

213,000

215,000

Defined Contribution Plan Contributions By Employer [Abstract]

Savings plan matching contributions

19,000

22,000

PECO Energy Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

45,000

137,000

106,000

Federal subsidy payments received not included in contributions

1,000

2,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

50,000

32,000

46,000

Defined Contribution Plan Contributions By Employer [Abstract]

Savings plan matching contributions

7,000

9,000

Baltimore Gas and Electric Company [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

16,000

67,000

214,000

Federal subsidy payments received not included in contributions

2,000

3,000

2,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

60,000

51,000

48,000

Defined Contribution Plan Contributions By Employer [Abstract]

Savings plan matching contributions

7,000

6,000

Pension Plans Defined Benefit [Member]

Change in benefit obligation:

Net benefit obligation at beginning of year

13,538,000

12,524,000

Service cost

280,000

212,000

190,000

Interest cost

698,000

649,000

660,000

Actuarial gain (loss)

1,520,000

807,000

Acquisitions/divestitures

1,880,000

Curtailments

(10,000)

Settlements

(169,000)

Special termination benefits

15,000

Gross benefits paid

(952,000)

(654,000)

Net benefit obligation at end of year

16,800,000

13,538,000

12,524,000

Change in plan assets:

Fair value of net plan assets at beginning of year

11,302,000

8,859,000

Actual return on plan assets

1,484,000

1,003,000

Employer contributions

149,000

2,094,000

Gross benefits paid

(952,000)

(654,000)

Settlements

(169,000)

Fair value of net plan assets at end of year

13,357,000

11,302,000

8,859,000

Components of net periodic benefit cost:

Service cost

280,000

212,000

190,000

Interest cost

698,000

649,000

660,000

Expected return on assets

(988,000)

(939,000)

(799,000)

Amortization of:

Prior service cost (credit)

15,000

14,000

Actuarial (loss) gain

450,000

331,000

254,000

Curtailments charges

Settlement charges

(31,000)

(5,000)

Contractual termination benefit cost

(14,000)

Net periodic benefit cost

500,000

267,000

324,000

Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]

Other current liabilities

15,000

42,000

Pension obligations

3,428,000

2,194,000

Unfunded status (net benefit obligation less net plan assets)

3,443,000

2,236,000

Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:

Current year actuarial (gain) loss

1,693,000

744,000

737,000

Amortization of actuarial gain (loss)

(450,000)

(331,000)

(254,000)

Current year prior service cost

1,000

Amortization of prior service cost

(15,000)

(14,000)

Curtailments

(10,000)

Settlements

(5,000)

Total recognized in OCI and regulatory assets

^[2]

1,188,000

399,000

464,000

Changes in plan assets and benefit obligations recognized in OCI

283,000

181,000

310,000

Changes in plan assets and benefit obligations recognized in regulatory assets

904,000

218,000

154,000

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax [Abstract]

Prior service cost (credit)

76,000

90,000

Actuarial loss

7,931,000

6,729,000

Total components of periodic benefit cost not yet recognized

^[3]

8,007,000

6,819,000

Benefits included in accumulated other comprehensive income

4,594,000

4,000

Benefits included in regulatory assets

3,413,000

2,000

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets To Be Amortized Before Tax [Abstract]

Prior service cost (credit)

14,000

Actuarial loss

568,000

Total components of periodic benefit cost to be amortized

^[4]

582,000

Benefits included in accumulated other comprehensive income

315,000

Benefits included in regulatory assets

267,000

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

149,000

$ 2,094,000

766,000

Defined Benefit Plan Estimated Future Benefit Payments [Abstract]

Defined Benefit Plan Expected Future Benefit Payments In Year One

943,000

Defined Benefit Plan Expected Future Benefit Payments In Year Two

807,000

Defined Benefit Plan Expected Future Benefit Payments In Year Three

891,000

Defined Benefit Plan Expected Future Benefit Payments In Year Four

868,000

Defined Benefit Plan Expected Future Benefit Payments In Year Five

902,000

Defined Benefit Plan Expected Future Benefit Payments In Five Fiscal Years Thereafter

5,161,000

Total estimated future benefits payments through 2020

$ 9,572,000

Pension Plans Defined Benefit [Member] | Equity Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

34.00%

Total weighted average asset allocation

35.00%

Pension Plans Defined Benefit [Member] | Fixed Income Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

40.00%

47.00%

Pension Plans Defined Benefit [Member] | Alternative Investments [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

26.00%

21.00%

Total weighted average asset allocation

25.00%

Pension Plans Defined Benefit [Member] | Business Services Company [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

$ 63,000

$ 157,000

77,000

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

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

48,000

954,000

356,000

Pension Plans Defined Benefit [Member] | Commonwealth Edison Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

25,000

873,000

260,000

Pension Plans Defined Benefit [Member] | PECO Energy Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

13,000

110,000

73,000

Pension Plans Defined Benefit [Member] | Baltimore Gas and Electric Company [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

54,000

197,000

Other Postretirement Benefit Plans Defined Benefit [Member]

Change in benefit obligation:

Net benefit obligation at beginning of year

4,062,000

3,874,000

Service cost

156,000

142,000

124,000

Interest cost

205,000

207,000

214,000

Plan participants' contributions

34,000

25,000

Actuarial gain (loss)

313,000

4,000

Plan amendments

(103,000)

Curtailments

(8,000)

Special termination benefits

(6,000)

(1,000)

Gross benefits paid

(219,000)

(201,000)

Federal subsidy on benefits paid

12,000

11,000

Net benefit obligation at end of year

4,820,000

4,062,000

3,874,000

Reinsurance proceeds received

12,000

Change in plan assets:

Fair value of net plan assets at beginning of year

1,797,000

1,655,000

Actual return on plan assets

197,000

29,000

Employer contributions

325,000

277,000

Plan participants' contributions

34,000

25,000

Gross benefits paid

(219,000)

(201,000)

Benefits paid net

(218,000)

Fair value of net plan assets at end of year

2,135,000

1,797,000

1,655,000

Components of net periodic benefit cost:

Service cost

156,000

142,000

124,000

Interest cost

205,000

207,000

214,000

Expected return on assets

(115,000)

(111,000)

(109,000)

Amortization of:

Transition obligation

11,000

9,000

Prior service cost (credit)

(17,000)

(38,000)

(56,000)

Actuarial (loss) gain

81,000

66,000

74,000

Curtailments charges

7,000

Net periodic benefit cost

320,000

275,000

257,000

Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]

Other current liabilities

23,000

2,000

Non-pension postretirement benefit obligations

2,662,000

2,263,000

Unfunded status (net benefit obligation less net plan assets)

2,685,000

2,265,000

Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:

Current year actuarial (gain) loss

304,000

74,000

Amortization of actuarial gain (loss)

(81,000)

(66,000)

(74,000)

Current year prior service cost

(109,000)

Amortization of prior service cost

17,000

38,000

56,000

Current year transition (asset) obligation

(1,000)

Amortization of transition obligation

(11,000)

(9,000)

Curtailments

(1,000)

Total recognized in OCI and regulatory assets

^[2]

120,000

37,000

(27,000)

Changes in plan assets and benefit obligations recognized in OCI

39,000

13,000

(9,000)

Changes in plan assets and benefit obligations recognized in regulatory assets

81,000

24,000

(18,000)

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax [Abstract]

Transition obligation

11,000

Prior service cost (credit)

(107,000)

(16,000)

Actuarial loss

1,185,000

963,000

Total components of periodic benefit cost not yet recognized

^[3]

1,078,000

958,000

Benefits included in accumulated other comprehensive income

514,000

4,000

Benefits included in regulatory assets

564,000

4,000

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets To Be Amortized Before Tax [Abstract]

Transition obligation

Prior service cost (credit)

(19,000)

Actuarial loss

84,000

Total components of periodic benefit cost to be amortized

^[4]

65,000

Benefits included in accumulated other comprehensive income

29,000

Benefits included in regulatory assets

36,000

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

323,000

277,000

203,000

Defined Benefit Plan Estimated Future Benefit Payments [Abstract]

Defined Benefit Plan Expected Future Benefit Payments In Year One

197,000

Defined Benefit Plan Expected Future Benefit Payments In Year Two

204,000

Defined Benefit Plan Expected Future Benefit Payments In Year Three

212,000

Defined Benefit Plan Expected Future Benefit Payments In Year Four

220,000

Defined Benefit Plan Expected Future Benefit Payments In Year Five

231,000

Defined Benefit Plan Expected Future Benefit Payments In Five Fiscal Years Thereafter

1,330,000

Total estimated future benefits payments through 2020

2,394,000

Disclosure Of Expected Gross Prescription Drug Subsidy Receipts [Abstract]

Prescription Drug Subsidy Receipts Year One

Prescription Drug Subsidy Receipts Year Two

Prescription Drug Subsidy Receipts Year Three

Prescription Drug Subsidy Receipts Year Four

Prescription Drug Subsidy Receipts Year Five

Prescription Drug Subsidy Receipts Five Fiscal Years Thereafter

$ 0

Other Postretirement Benefit Plans Defined Benefit [Member] | Equity Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

45.00%

Total weighted average asset allocation

46.00%

Other Postretirement Benefit Plans Defined Benefit [Member] | Fixed Income Securities [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

40.00%

Other Postretirement Benefit Plans Defined Benefit [Member] | Alternative Investments [Member]

Defined Benefit Plan Weighted Average Asset Allocations [Abstract]

Target asset allocation percentage

15.00%

Other Postretirement Benefit Plans Defined Benefit [Member] | Business Services Company [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

$ 24,000

20,000

14,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

135,000

121,000

94,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Commonwealth Edison Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

119,000

108,000

60,000

Other Postretirement Benefit Plans Defined Benefit [Member] | PECO Energy Co [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

33,000

$ 28,000

$ 35,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Baltimore Gas and Electric Company [Member]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

^[5]

$ 12,000

[1]	These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. The amounts included in capital and operating and maintenance expense for the years ended 2012, 2011, and 2010 include $12 million, $51 million, and $48 million, respectively, in costs incurred prior to the closing of Exelon’s merger with Constellation on March 12, 2012. These amounts are not included in Exelon’s capital and operating and maintenance expense for the years ended 2012, 2011, and 2010. BGE’s pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset.
[2]	Of the $1,188 million related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $464 million related to pension benefits, $310 million and $154 million were recognized in AOCI and regulatory assets, respectively, during 2010. Of the $(27) million related to other postretirement benefits, $(9) million and $(18) million were recognized in AOCI and regulatory assets, respectively, during 2010.
[3]	Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $6,819 million related to pension benefits, $4,311 million and $2,508 million are included in AOCI and regulatory assets, respectively, at December 31, 2011. Of the $958 million related to other postretirement benefits, $475 million and $483 million are included in AOCI and regulatory assets, respectively, at December 31, 2011.
[4]	Of the $582 million related to pension benefits at December 31, 2012, $315 million and $267 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $65 million related to other postretirement benefits at December 31, 2012, $29 million and $36 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively.
[5]	The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011, and $10 million, $5 million, $3 million, $2 million and $2 million, respectively, in 2010.

Retirement Benefits - Assumptions Used In Calculations (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract]
Discount rate	3.92%	4.74%	5.26%
Rate of compensation increase	3.25%	3.75%	3.75%
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	7.50%		8.50%
Discount rate			5.83%
Rate of compensation increase	3.75%	3.75%	4.00%
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract]
Discount rate	4.00%	4.80%	5.30%
Rate of compensation increase	3.25%	3.75%	3.75%
Healthcare cost trend on covered charges	6.50%	6.50%	7.00%
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	6.68%		7.83%
Discount rate			5.83%
Rate of compensation increase	3.75%	3.75%	4.00%
Healthcare cost trend on covered charges	6.50%	7.00%	7.50%

Retirement Benefits - Fair Value Recurring Basis (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Cash equivalents

^[1]

$ 995,000

$ 861,000

Equity Securities [Abstract]

Individually held

1,985,000

Mutual funds

4,000

Fixed income [Abstract]

Real estate

125,000

Total pension and other postretirement benefit plan assets

15,411,000

12,986,000

Pension Plans Defined Benefit [Member]

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Cash equivalents

1,000

8,000

Equity Securities [Abstract]

Individually held

2,562,000

Commingled funds

1,111,000

858,000

Mutual funds

323,000

389,000

Equity securities subtotal

3,996,000

3,232,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,037,000

1,664,000

Debt securities issued by states of the United States and political subdivisions of the states

108,000

88,000

Foreign debt

252,000

224,000

Corporate debt securities

3,330,000

2,561,000

Federal agency mortgage-backed securities

117,000

156,000

Non-federal agency mortgage-backed securities

28,000

Commingled funds fixed income

274,000

202,000

Mutual funds fixed income

295,000

277,000

Fixed income subtotal

5,429,000

5,200,000

Hedge funds

2,315,000

1,525,000

Private equity

754,000

672,000

Real estate

Pension plan assets subtotal

13,276,000

11,198,000

Pension Plans Defined Benefit [Member] | Individually Held [Member]

Fixed income [Abstract]

Real estate

280,000

207,000

Pension Plans Defined Benefit [Member] | Commingled Funds [Member]

Fixed income [Abstract]

Real estate

75,000

125,000

Pension Plans Defined Benefit [Member] | Real Estate Funds [Member]

Fixed income [Abstract]

Real estate

426,000

229,000

Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Derivative Instruments

9,000

Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Derivative Instruments

(21,000)

Other Postretirement Benefit Plans Defined Benefit [Member]

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Cash equivalents

44,000

73,000

Equity Securities [Abstract]

Individually held

198,000

110,000

Commingled funds

530,000

415,000

Mutual funds

230,000

171,000

Equity securities subtotal

958,000

696,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

18,000

29,000

Debt securities issued by states of the United States and political subdivisions of the states

125,000

93,000

Foreign debt

3,000

4,000

Corporate debt securities

50,000

41,000

Federal agency mortgage-backed securities

52,000

34,000

Non-federal agency mortgage-backed securities

6,000

7,000

Commingled funds fixed income

271,000

385,000

Mutual funds fixed income

297,000

256,000

Fixed income subtotal

822,000

849,000

Hedge funds

200,000

157,000

Private equity

1,000

Real estate

Postretirement benefit plan subtotal

2,135,000

1,788,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Individually Held [Member]

Fixed income [Abstract]

Real estate

7,000

4,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Commingled Funds [Member]

Fixed income [Abstract]

Real estate

2,000

1,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member]

Fixed income [Abstract]

Real estate

101,000

7,000

Fair Value Inputs Level 1 [Member]

Fixed income [Abstract]

Total pension and other postretirement benefit plan assets

4,999,000

4,029,000

Fair Value Inputs Level 1 [Member] | Pension Plans Defined Benefit [Member]

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Cash equivalents

1,000

8,000

Equity Securities [Abstract]

Individually held

2,562,000

1,985,000

Mutual funds

323,000

Equity securities subtotal

2,885,000

1,985,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,037,000

1,616,000

Fixed income subtotal

1,041,000

1,616,000

Real estate

Pension plan assets subtotal

4,207,000

3,816,000

Fair Value Inputs Level 1 [Member] | Pension Plans Defined Benefit [Member] | Individually Held [Member]

Fixed income [Abstract]

Real estate

280,000

207,000

Fair Value Inputs Level 1 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member]

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Cash equivalents

44,000

73,000

Equity Securities [Abstract]

Individually held

198,000

110,000

Mutual funds

230,000

Equity securities subtotal

428,000

110,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

18,000

26,000

Mutual funds fixed income

295,000

Fixed income subtotal

313,000

26,000

Real estate

Postretirement benefit plan subtotal

792,000

213,000

Fair Value Inputs Level 1 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Individually Held [Member]

Fixed income [Abstract]

Real estate

7,000

4,000

Fair Value Inputs Level 2 [Member]

Fixed income [Abstract]

Total pension and other postretirement benefit plan assets

7,889,000

6,366,000

Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member]

Equity Securities [Abstract]

Commingled funds

1,111,000

858,000

Mutual funds

389,000

Equity securities subtotal

1,111,000

1,247,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

48,000

Debt securities issued by states of the United States and political subdivisions of the states

108,000

88,000

Foreign debt

252,000

224,000

Corporate debt securities

3,330,000

2,561,000

Federal agency mortgage-backed securities

117,000

156,000

Non-federal agency mortgage-backed securities

28,000

Commingled funds fixed income

274,000

202,000

Mutual funds fixed income

291,000

277,000

Fixed income subtotal

4,388,000

3,584,000

Hedge funds

1,080,000

Real estate

Pension plan assets subtotal

6,654,000

4,956,000

Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Commingled Funds [Member]

Fixed income [Abstract]

Real estate

75,000

Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Assets [Member]

Fixed income [Abstract]

Derivative Instruments

9,000

Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Liabilities [Member]

Fixed income [Abstract]

Derivative Instruments

(21,000)

Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member]

Equity Securities [Abstract]

Commingled funds

530,000

415,000

Mutual funds

171,000

Equity securities subtotal

530,000

586,000

Fixed income [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

3,000

Debt securities issued by states of the United States and political subdivisions of the states

125,000

93,000

Foreign debt

3,000

4,000

Corporate debt securities

50,000

41,000

Federal agency mortgage-backed securities

52,000

34,000

Non-federal agency mortgage-backed securities

6,000

7,000

Commingled funds fixed income

271,000

385,000

Mutual funds fixed income

2,000

256,000

Fixed income subtotal

509,000

823,000

Hedge funds

188,000

Real estate

Postretirement benefit plan subtotal

1,235,000

1,410,000

Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Commingled Funds [Member]

Fixed income [Abstract]

Real estate

2,000

1,000

Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member]

Fixed income [Abstract]

Real estate

6,000

Fair Value Inputs Level 3 [Member]

Fixed income [Abstract]

Hedge funds

1,525,000

Total pension and other postretirement benefit plan assets

2,523,000

2,591,000

Fair Value Inputs Level 3 [Member] | Pension Plans Defined Benefit [Member]

Fixed income [Abstract]

Hedge funds

1,235,000

Private equity

754,000

672,000

Real estate

Pension plan assets subtotal

2,415,000

2,426,000

Fair Value Inputs Level 3 [Member] | Pension Plans Defined Benefit [Member] | Real Estate Funds [Member]

Fixed income [Abstract]

Real estate

426,000

229,000

Fair Value Inputs Level 3 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member]

Fixed income [Abstract]

Fixed income subtotal

Hedge funds

12,000

157,000

Private equity

1,000

Real estate

Postretirement benefit plan subtotal

108,000

165,000

Fair Value Inputs Level 3 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member]

Fixed income [Abstract]

Real estate

$ 95,000

$ 7,000

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

Retirement Benefits - Fair Value Unobservable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Actual return on plan assets:
Transfers into (out of) Level 3	$ (188,000)
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	2,426,000	$ 1,044,000
Actual return on plan assets:
Relating to assets still held at the reporting date	217,000	104,000
Purchases	689,000	1,356,000
Sales	(6,000)	0
Settlements	(160,000)	(78,000)
Transfers into (out of) Level 3	(751,000)
Fair value of net plan assets at end of year	2,415,000	2,426,000
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	165,000	13,000
Actual return on plan assets:
Relating to assets still held at the reporting date	14,000	(4,000)
Purchases	123,000	156,000
Settlements	(1,000)
Transfers into (out of) Level 3	(193,000)
Fair value of net plan assets at end of year	108,000	165,000
Hedge Fund Investments [Member] \| Pension Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	1,525,000
Actual return on plan assets:
Relating to assets still held at the reporting date	138,000	(26,000)
Purchases	447,000	1,222,000
Sales	(6,000)
Settlements	(4,000)
Transfers into (out of) Level 3	(865,000)
Fair value of net plan assets at end of year	1,235,000	1,525,000
Hedge Fund Investments [Member] \| Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	157,000	5,000
Actual return on plan assets:
Relating to assets still held at the reporting date	11,000	(3,000)
Purchases	32,000	155,000
Fair value of net plan assets at end of year	12,000	157,000
Commingled Funds In Private Equity Investments [Member] \| Pension Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	672,000	536,000
Actual return on plan assets:
Relating to assets still held at the reporting date	55,000	84,000
Purchases	108,000	121,000
Sales	0
Settlements	(128,000)	(69,000)
Transfers into (out of) Level 3	47,000
Fair value of net plan assets at end of year	754,000	672,000
Commingled Funds In Private Equity Investments [Member] \| Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	1,000
Actual return on plan assets:
Purchases	0	1,000
Fair value of net plan assets at end of year	1,000	1,000
Commingled Funds In Direct Real Estate [Member] \| Pension Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	229,000	179,000
Actual return on plan assets:
Relating to assets still held at the reporting date	24,000	46,000
Purchases	134,000	13,000
Sales	0	0
Settlements	(28,000)	(9,000)
Transfers into (out of) Level 3	67,000
Fair value of net plan assets at end of year	426,000	229,000
Commingled Funds In Direct Real Estate [Member] \| Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Line Items]
Fair value of net plan assets at beginning of year	7,000	8,000
Actual return on plan assets:
Relating to assets still held at the reporting date	3,000	(1,000)
Purchases		0
Settlements	(1,000)
Transfers into (out of) Level 3	(5,000)	0
Fair value of net plan assets at end of year	$ 95,000	$ 7,000

Retirement Benefits - Additional (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Healthcare Reform Legislation Impact [Abstract]
After-tax charge to income tax expense as a result of health care reform legislation	$ 65,000
Excise tax on certain high-cost benefit plans	40.00%
Components Of Net Periodic Benefit Costs [Abstract]
Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act	$ (17,000)	$ 28,000	$ 38,000
Securities Lending Program [Abstract]
Fair value of securities on loan	17,000
Fair value of cash and non-cash collateral received for loan securities	$ 17,000
Projected Benefit Obligation In Excess Of Plan Assets [Member]
Benefit Obligation and Plan Assets, and Funded Status [Abstract]
Funded status of the pension and other postretirement benefit obligations	80.00%
Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Benefit Obligation and Plan Assets, and Funded Status [Abstract]
Funded status of the pension and other postretirement benefit obligations	85.00%
Exelon Generation Co L L C [Member]
Healthcare Reform Legislation Impact [Abstract]
After-tax charge to income tax expense as a result of health care reform legislation	$ 24,000
Commonwealth Edison Co [Member]
Healthcare Reform Legislation Impact [Abstract]
After-tax charge to income tax expense as a result of health care reform legislation	11,000
PECO Energy Co [Member]
Healthcare Reform Legislation Impact [Abstract]
After-tax charge to income tax expense as a result of health care reform legislation	9,000
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Contributions [Abstract]
Expected other postretirement benefit plan contributions	$ 4,000	$ 13,000	$ 17,000

Plant Retirements (Details) $ in Thousands	12 Months Ended		37 Months Ended
Plant Retirements (Details) $ in Thousands	Dec. 31, 2012 USD ($) MW ElectricGenerationStation	Dec. 31, 2011 USD ($)	Dec. 31, 2012 USD ($) MW ElectricGenerationStation
Plant Retirements Costs [Abstract]
Inventory write down related to plant retirements	$ 6,000
Exelon Generation Co L L C [Member]
Plant Retirements Reserve [Line Items]
Severance benefit obligation - beginning balance	7,000	$ 7,000
Severance charges recorded	0	4,000
Cash payments	(4,000)	(4,000)
Severance benefit obligation - ending balance	3,000	7,000	$ 3,000
Plant Retirements Costs [Abstract]
Plant retirement costs incurred			44,000
Severance benefits expense related to plant retirements		4,000	13,000
Inventory write down related to plant retirements	6,000		18,000
Plant shut-down costs	11,000	$ 2,000	$ 13,000
Exelon Generation Co L L C [Member] \| Eddystone Generating Station [Member]
Plant Retirements Reliability Must Run Revenue [Abstract]
Monthly revenue during reliability-must-run period	$ 6,000
Exelon Generation Co L L C [Member] \| Schuylkill Station Unit One [Member]
Plant Retirement Positions Eliminated [Abstract]
Oil/gas-fired generation unit to be retired \| MW	166		166
Exelon Generation Co L L C [Member] \| Riverside Station Unit Six [Member]
Plant Retirement Positions Eliminated [Abstract]
Oil/gas-fired generation unit to be retired \| ElectricGenerationStation	115		115
Commonwealth Edison Co [Member]
Plant Retirements Costs [Abstract]
Inventory write down related to plant retirements	$ 1,000

Preferred Securities (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Class of Stock [Line Items]

Shares outstanding

1,900,000

Dollar amount

$ 190,000

Temporary Equity [Line Items]

Shares outstanding

874,720

Dollar amount

$ 87,000

Preferred Stock [Member]

Preferred Securities Additional Narrative Information [Line Items]

Shares authorized

100,000,000

Series A Preferred Stock [Member]

Temporary Equity [Line Items]

Shares outstanding

300,000

Dollar amount

$ 30,000

Redemption price

$ 106.00

Dividend rate per dollar amount

$ 3.80

Series B Preferred Stock [Member]

Temporary Equity [Line Items]

Shares outstanding

150,000

Dollar amount

$ 15,000

Redemption price

$ 102.00

Dividend rate per dollar amount

$ 4.30

Series C Preferred Stock [Member]

Temporary Equity [Line Items]

Shares outstanding

274,720

Dollar amount

$ 27,000

Redemption price

$ 112.50

Dividend rate per dollar amount

$ 4.40

Series D Preferred Stock [Member]

Temporary Equity [Line Items]

Shares outstanding

150,000

Dollar amount

$ 15,000

Redemption price

$ 104.00

Dividend rate per dollar amount

$ 4.68

Series 6.97% Preferred Stock [Member]

Class of Stock [Line Items]

Shares outstanding

500,000

Dollar amount

$ 50,000

Redemption price

^[1]

$ 100.35

Dividend Rate Percentage

6.97%

Series 6.7% Preferred Stock [Member]

Class of Stock [Line Items]

Shares outstanding

400,000

Dollar amount

$ 40,000

Redemption price

^[1]

$ 100.67

Dividend Rate Percentage

6.70%

Series 6.99% Preferred Stock [Member]

Class of Stock [Line Items]

Shares outstanding

600,000

Dollar amount

$ 60,000

Redemption price

^[1]

$ 101.05

Dividend Rate Percentage

6.99%

Series 7.125% Preferred Stock [Member]

Class of Stock [Line Items]

Shares outstanding

400,000

Dollar amount

$ 40,000

Redemption price

^[1]

$ 100.36

Dividend Rate Percentage

7.125%

Commonwealth Edison Co [Member] | Preferred Stock [Member]

Preferred Securities Additional Narrative Information [Line Items]

Shares authorized

850,000

Commonwealth Edison Co [Member] | Cumulative Preferred Stock [Member]

Preferred Securities Additional Narrative Information [Line Items]

Shares authorized

6,810,451

PECO Energy Co [Member]

Temporary Equity [Line Items]

Dollar amount

$ 87,000

PECO Energy Co [Member] | Cumulative Preferred Stock [Member]

Preferred Securities Additional Narrative Information [Line Items]

Shares authorized

15,000,000

Baltimore Gas and Electric Company [Member] | Preference Stock [Member]

Preferred Securities Additional Narrative Information [Line Items]

Shares authorized

6,500,000

Preferred Stock, Par or Stated Value Per Share

$ 100

[1]	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

Common Stock (Details)

12 Months Ended

Dec. 31, 2012

USD ($)

Warrants

$ / shares

Dec. 31, 2011

USD ($)

Warrants

$ / shares

Dec. 31, 2010

USD ($)

$ / shares

Jun. 30, 2012

USD ($)

Jan. 31, 2011

Common Stock [Abstract]

Common Stock without par - Authorized

2,000,000,000

Common Stock without par - Outstanding

854,781,389

663,368,958

855,019,272

Common Stock par - Authorized

250,000,000

Common Stock reserved for warrants

24,727

Authorized Shares for LTIP [Abstract]

Authorized Shares for LTIP

20,000,000

Share Based Compensation Components [Abstract]

Performance shares | $

$ 46,000,000

$ 26,000,000

$ 6,000,000

Stock options | $

15,000,000

8,000,000

10,000,000

Restricted stock units | $

50,000,000

31,000,000

21,000,000

Other stock-based awards | $

4,000,000

Total stock-based compensation included in operating and maintenance expense | $

115,000,000

69,000,000

41,000,000

Income Tax Benefit | $

(44,000,000)

(27,000,000)

(16,000,000)

Total after-tax stock based compensation expense | $

71,000,000

42,000,000

25,000,000

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

115,000,000

^[1]

69,000,000

41,000,000

Realized tax benefit when exercised/distributed:

Stock options | $

3,000,000

2,000,000

5,000,000

Restricted stock units | $

11,000,000

8,000,000

9,000,000

Performance share awards | $

7,000,000

13,000,000

Stock deferral plan | $

1,000,000

Excess tax benefits included in other financing activities of Exelon's Consolidated Statements of Cash Flows:

Stock options | $

2,000,000

1,000,000

3,000,000

Restricted stock units | $

Performance share awards | $

Stock deferral plan | $

$ 0

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Exercised - shares

(1,776,041)

Exercisable stock options - aggregate intrinsic value | $

$ 13,000,000

Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward

Stock Based Compensation Other Than Options Converted Acquiree

11,194,151

Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract]

Fully vested stock based compensation issued to retirement-eligible employees

448,827

Stock based compensation issued to retirement eligible employees that vested immediately on the date of the grant.

1,348,000

Fair value of each option estimated using the Black-Scholes-Merton option-pricing model

Dividend yield

0.0528%

0.0484%

0.0456%

Expected volatility

0.232%

0.244%

0.271%

Risk-free interest rate

0.013%

0.0265%

0.0296%

Expected life (years)

6 years 3 months 1 day

Weighted average grant date fair value | $ / shares

$ 4.18

$ 6.22

$ 8.08

Additional Information Regarding Stock Options Exercised [Abstract]

Intrinsic value | $

^[2]

$ 19,000,000

$ 5,000,000

$ 13,000,000

Cash received for exercise price | $

47,000,000

13,000,000

24,000,000

Unrecognized compensation costs related to nonvested stock options | $

$ 6,000,000

Weighted Average Period Non Vested Stock Options Are Expected To Be Recognized Over

2 years 5 months

Restricted Stock Units [Abstract]

Weighted average grant date fair value | $

$ 39.94

43.33

44.23

46,000,000

$ 58,000,000

43,000,000

Fair value of settled restricted stock | $

25,000,000

19,000,000

22,000,000

Performance Share Awards [Abstract]

Weighted average grant date fair value | $

39.71

43.52

60.82

Performance shares settled at fair value of | $

23,000,000

22,000,000

32,000,000

Performance shares settled at fair value and paid with cash | $

3,000,000

10,000,000

20,000,000

Unrecognized compensation costs related to nonvested performance shares | $

$ 9,000,000

Weighted average period

1 year 11 months

Current Liabilities | $

^[3]

$ 7,000,000

3,000,000

Deferred credits and other liabilities | $

^[4]

11,000,000

Common stock | $

35,000,000

30,000,000

Total | $

$ 53,000,000

33,000,000

Share Repurchases [Abstract]

Number of shares of common stock purchased under 2004 share repurchase program

35,000,000

Value of shares of common stock purchased under 2004 share repurchase program | $

$ 2,300,000,000

Approved number of shares of common stock for repurchased under Q3 2008 share repurchase program | $

1,500,000,000

Exelon Generation Co L L C [Member]

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

$ 42,000,000

^[1]

$ 31,000,000

21,000,000

Commonwealth Edison Co [Member]

Common Stock [Abstract]

Par value of common stock | $ / shares

$ 12.50

Common Stock par - Authorized

250,000,000

Common Stock par - Outstanding

127,016,761

127,016,529

127,016,761

Warrants Outstanding | Warrants

74,182

75,096

Common Stock reserved for warrants

25,032

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

$ 11,000,000

^[1]

$ 5,000,000

3,000,000

PECO Energy Co [Member]

Common Stock [Abstract]

Common Stock without par - Authorized

500,000,000

Common Stock without par - Outstanding

170,478,507

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

$ 5,000,000

^[1]

$ 5,000,000

3,000,000

Baltimore Gas and Electric Company [Member]

Common Stock [Abstract]

Common Stock without par - Authorized

175,000,000

Common Stock without par - Outstanding

1,000

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

$ 6,000,000

4,000,000

Business Services Company [Member]

Share Based Compensation Pre Tax Expense [Line Items]

Pre-tax stock based compensation expense | $

^[5]

$ 52,000,000

^[1]

$ 28,000,000

$ 14,000,000

Stock Options [Member]

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Shares outstanding, beginning balance - shares

11,553,761

Granted - shares

2,372,000

Converted Options Acquiree

11,194,151

Forfeited - shares

(980,986)

Expired - shares

(459,104)

Shares outstanding, ending balance - shares

21,903,781

11,553,761

Exercisable stock options - shares

^[6]

19,943,116

Shares outstanding, beginning balance - weighted average exercise price (per share) | $ / shares

$ 48.49

Grants - weighted average exercise price (per share) | $ / shares

39.66

Converted options of acquiree | $ / shares

41.35

Exercised - weighted average exercise price (per share) | $ / shares

26.41

Forfeited - weighted average exercise price (per share) | $ / shares

42.90

Expired - weighted average exercise price (per share) | $ / shares

49.45

Shares outstanding, ending balance - weighted average exercise price (per share) | $ / shares

45.91

$ 48.49

Exercisable stock options - weighted average exercise price (per share) | $ / shares

^[6]

$ 46.40

Shares outstanding, ending balance - weighted average remaining contractual life (years)

5 years 7 months 2 days

Exercisable stock options - weighted average remaining contractual life (years)

5 years 3 months 1 day

Shares outstanding, ending balance - aggregate intrinsic value | $

$ 13,000,000

Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract]

Fully vested stock based compensation issued to retirement-eligible employees

1,699,000

Stock based compensation issued to retirement eligible employees that vested immediately on the date of the grant.

2,647,536

Share Based Compensation Acquisition Arrangement [Abstract]

Fair value of stock based compensation used of acquiree | $

$ 71,000,000

Stock based compensation of acquiree converted

12,037,093

Stock Based Compensation Converted Acquirer Shares

11,194,151

Value of stock based compensation converted | $

$ 65,000,000

No Sale Restricted Stock of Acquiree converted

165,219,000,000

Nonvested Stock Option [Member]

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Shares outstanding, beginning balance - shares

^[7]

877,050

Granted - shares

^[8]

2,372,000

Vested - shares

^[8]

(12,023,432)

Forfeited - shares

(459,104)

Shares outstanding, ending balance - shares

^[7]

1,960,665

877,050

Shares outstanding, beginning balance - weighted average exercise price (per share) | $ / shares

^[7]

$ 48.66

Grants - weighted average exercise price (per share) | $ / shares

^[8]

39.66

Vested - weighted average exercise price (per share) | $ / shares

^[8]

41.37

Forfeited - weighted average exercise price (per share) | $ / shares

49.45

Shares outstanding, ending balance - weighted average exercise price (per share) | $ / shares

^[7]

$ 40.56

$ 48.66

Restricted Stock [Member]

Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward

Equity instruments other than options - shares, beginning balance

^[9]

1,074,484

Granted - shares

1,332,214

Stock Based Compensation Other Than Options Converted Acquiree

825,735

Vested - shares

(479,805)

Forfeited - shares

(76,484)

Undistributed Vested Awards - shares

^[10]

(646,983)

Equity instruments other than options - shares, ending balance

^[9]

2,029,161

1,074,484

Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $ / shares

^[9]

$ 48.08

Granted - Weighted average grant date fair value (per share) | $ / shares

39.94

Vested - Weighted average grant date fair value (per share) | $ / shares

46.36

Forfeited - Weighted average grant date fair value (per share) | $ / shares

42.21

Undistributed Vested Awards - weighted average exercise price (per share) | $ / shares

^[10]

40.75

Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $ / shares

^[9]

$ 42.12

$ 48.08

Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract]

Fully vested stock based compensation issued to retirement-eligible employees

686,121

Share Based Compensation Acquisition Arrangement [Abstract]

No Sale Restricted Stock Converted Shares

153,654

No Sale Restricted Stock Converted Value | $

$ 6,000,000

Performance Share Awards [Member]

Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward

Equity instruments other than options - shares, beginning balance

^[11]

346,848

Granted - shares

1,429,189

Vested - shares

(167,048)

Forfeited - shares

(116,388)

Undistributed Vested Awards - shares

^[12]

(179,867)

Equity instruments other than options - shares, ending balance

^[11]

1,312,734

346,848

Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $ / shares

^[11]

$ 45.37

Granted - Weighted average grant date fair value (per share) | $ / shares

39.72

Vested - Weighted average grant date fair value (per share) | $ / shares

47.46

Forfeited - Weighted average grant date fair value (per share) | $ / shares

39.78

Undistributed Vested Awards - weighted average exercise price (per share) | $ / shares

^[12]

40.72

Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $ / shares

^[11]

$ 40.08

$ 45.37

Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract]

Fully vested stock based compensation issued to retirement-eligible employees

204,643

455,418

[1]	For BGE, reflects BGE's stock-based compensation expense for the year ended December 31, 2012. For Exelon and Generation, includes the stock-based compensation expense of Constellation and BGE from the date of the merger, March 12, 2012, through December 31, 2012.
[2]	The difference between the market value on the date of exercise and the option exercise price.
[3]	Represents the current liability related to performance share awards expected to be settled in cash.
[4]	Represents the long-term liability related to performance share awards expected to be settled in cash.
[5]	(a) For BGE, reflects BGE's stock-based compensation expense for the year ended December 31, 2012. For Exelon and Generation, includes the stock-based compensation expense of Constellation and BGE from the date of the merger, March 12, 2012, through December 31, 2012. (b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.
[6]	Includes stock options issued to retirement eligible employees.
[7]	Excludes 2,647,536 and 1,348,000 of stock options issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.
[8]	Includes 1,699,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.
[9]	Excludes 686,121 and 448,827 of restricted stock units issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.
[10]	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012.
[11]	Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.
[12]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012.

Earnings Per Share and Equity (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share And Equity Additional Narrative Information [Abstract]
Stock options not included in the calculation of diluted common shares outstanding									14,000	9,000	8,000
Treasury Stock, Shares held	35,000				35,000				35,000	35,000
Treasury stock, at cost	$ 2,327,000				$ 2,327,000				$ 2,327,000	$ 2,327,000
Earnings Per Share Diluted
Income from continuing operations
Income from discontinued operations
Net income on common stock									$ 1,160,000	$ 2,495,000	$ 2,563,000
Average common shares outstanding - basic	854,000	854,000	853,000	705,000	664,000	663,000	663,000	662,000	816,000	663,000	661,000
Assumed exercise of stock options, performance share awards and restricted stock									3,000	2,000	2,000
Average common shares outstanding - diluted	857,000	857,000	856,000	707,000	666,000	665,000	664,000	664,000	819,000	665,000	663,000

Commitments and Contingencies (Details)

1 Months Ended

9 Months Ended

12 Months Ended

Feb. 09, 2007

Jan. 31, 2005

Oct. 31, 2007

USD ($)

Sep. 30, 2010

USD ($)

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MultipleLiquidatingPreferred

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

Reactors

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

TimesLiquidatingValue

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

Defendants

Dec. 31, 2012

USD ($)

Tons

PoundsPerMWh

MGPSites

OpenClaims

Customers

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

States

Dec. 31, 2012

USD ($)

Tons

MGPSites

OpenClaims

Customers

NumberOfGridOperators

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Sep. 30, 2012

USD ($)

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

$ 15,350,000,000

$ 200,000,000

Guarantee obligations maximum exposure next twelve months

11,194,000,000

Guarantee obligations maximum exposure year two

203,000,000

Guarantee obligations maximum exposure year three

565,000,000

Guarantee obligations maximum exposure year four

6,000,000

Guarantee obligations maximum exposure year five

4,000,000

Guarantee obligations maximum exposure year six and beyond

3,378,000,000

Environmental Issues - Water [Abstract]

Consent decree penalty

$ 1,000,000

Environmental loss contingencies

$ 23,000,000

3,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term direct financing leases

685,000,000

$ 656,000,000

Probable contingency (liability)

$ 14,000,000

Climate Change Regulation [Abstract]

Minimum GHG emissions by stationary sources to qualify for regulation | Tons

75,000

Minimum additional GHG emissions by stationary sources after a modification | Tons

100,000

Minimum wattage subject to new source performance standards | MW

New source performance standard emissions limit | PoundsPerMWh

1,000

New source performance standard emissions limit first ten years | PoundsPerMWh

1,800

New source performance standard emissions limit after ten years | PoundsPerMWh

600

Asbestos Loss Contingency [Abstract]

Asbestos liability reserve related to open claims

$ 14,000,000

Open asbestos liability claims | OpenClaims

170

Asbestos liability reserve related to anticipated claims

$ 49,000,000

FERC Settlement [Abstract]

Number of States in PJM | States

Number of grid operators in New York ISO | NumberOfGridOperators

Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract]

Percentage of ownership interest in CENG (as a percent)

1.00%

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in one year

$ 88,000,000

Minimum future operating lease payments due in two years

83,000,000

Minimum future operating lease payments due in three years

73,000,000

Minimum future operating lease payments due in four years

69,000,000

Minimum future operating lease payments due in five years

63,000,000

Minimum future operating lease payments due beyond five years

488,000,000

Total minimum future operating lease payments

^[1]

864,000,000

$ 864,000,000

864,000,000

Operating Leases Rent Expense [Abstract]

Lease And Rental Expense

930,000,000

711,000,000

722,000,000

Sauer Dump [Member]

68th Street and Sauer Dumps [Abstract]

Number of defendants in addition to BGE and Constellation Energy | Defendants

Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

186,000,000

$ 186,000,000

186,000,000

Purchase Obligations, Due within Two Years

167,000,000

Purchase Obligations, Due within Three Years

114,000,000

Purchase Obligations, Due within Four Years

51,000,000

Purchase Obligations, Due within Five Years

49,000,000

Purchase Obligations, Due after Five Years

149,000,000

Purchase Obligations, Total

716,000,000

Financial Standby Letter of Credit [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

1,889,000,000

Guarantee obligations maximum exposure next twelve months

1,325,000,000

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

564,000,000

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

Surety Bond [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

286,000,000

Guarantee obligations maximum exposure next twelve months

225,000,000

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

1,000,000

Guarantee obligations maximum exposure year four

6,000,000

Guarantee obligations maximum exposure year five

4,000,000

Guarantee obligations maximum exposure year six and beyond

50,000,000

Property Lease Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

48,000,000

Guarantee obligations maximum exposure next twelve months

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

48,000,000

Performance Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

1,897,000,000

Guarantee obligations maximum exposure next twelve months

908,000,000

Guarantee obligations maximum exposure year two

203,000,000

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

786,000,000

Energy Contract Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

8,556,000,000

Guarantee obligations maximum exposure next twelve months

8,556,000,000

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

Commercial Commitments Footnote [Abstract]

Estimated total assumed for commercial transaction obligations

8,300,000

Nuclear Insurance Premiums [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

2,494,000,000

Guarantee obligations maximum exposure next twelve months

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

2,494,000,000

Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

Commercial Commitments Footnote [Abstract]

Estimated net exposure for commercial transaction obligations

1,500,000

Middle market lending commitment [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

180,000,000

Guarantee obligations maximum exposure next twelve months

180,000,000

Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

338,000,000

224,000,000

Accrual For MGP Investigation And Remediation [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

298,000,000

168,000,000

Exelon Generation Co L L C [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

7,462,000,000

Guarantee obligations maximum exposure next twelve months

4,159,000,000

Guarantee obligations maximum exposure year two

203,000,000

Guarantee obligations maximum exposure year three

563,000,000

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

2,537,000,000

Commercial Commitments Footnote [Abstract]

Guarantees in support of letters of credit

Nuclear Insurance [Abstract]

Nuclear insurance liability limit per incident

12,600,000,000

Required nuclear liability insurance per site

375,000,000

$ 375,000,000

375,000,000

Total of U.S. licensed nuclear reactors | Reactors

104

Nuclear financial protection pool value

12,200,000,000

$ 12,200,000,000

12,200,000,000

$ 12,200,000,000

12,200,000,000

Cost surcharge to Price-Anderson Act nuclear incident assessment

5.00%

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

117,500,000

$ 117,500,000

117,500,000

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

17,500,000

Maximum liability per nuclear incident

2,200,000,000

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

278,000,000

Total nuclear property insurance coverage

2,100,000,000

Nuclear property insurance coverage limit per individual insured

1,250,000,000

Additional nuclear property insurance purchased under single limit blanket property

850,000,000

Nuclear insurance property damage maximum retrospective premium obligation

220,000,000

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

3,200,000,000

Nuclear outage replacement power cost insurance maximum annual retrospective premium obligation

58,000,000

Spent Nuclear Fuel Obligation [Abstract]

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

0.001

Estimate increase in nuclear ARO due to delay in DOE acceptance of spent nuclear fuel for date one

700,000,000

Reimbursement for spent nuclear fuel costs

639,000,000

Net reimbursement for spent nuclear fuel cost after co-owner deduction

543,000,000

Requested SNF reimbursement costs from the DOE

61,000,000

Requested SNF reimbursement cost owed to co-owners

13,000,000

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

277,000,000

DOE SNF one-time fee with interest

1,020,000,000

$ 1,020,000,000

1,020,000,000

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

0.127%

Environmental Issues - Water [Abstract]

Low end of range of cooling tower cost

430,000,000

Total Conemaugh Station water discharge settlement to be paid by all responsible parties

500,000

Portion of Conemaugh Station water discharge settlement to be paid by Exelon

200,000

Environmental Issues - Air [Abstract]

SO2 emissions allowance impairment

$ 57,000,000

Emissions allowance balance

45,000,000

$ 45,000,000

45,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term direct financing leases

693,000,000

Asbestos Loss Contingency [Abstract]

Asbestos liability reserve

69,000,000

49,000,000

Asbestos reserve adjustment

19,000,000

US Department Of Energy Settlements [Abstract]

Preacquisition contingency asset DOE settlement gain

16,000,000

Funds received from DOE settlement

16,000,000

FERC Settlement [Abstract]

FERC civil penalty

135,000,000

FERC disgorgement

110,000,000

FERC disgorgement portion paid to each of six grid operators

1,000,000

FERC settlement recorded in operation and maintenance expense

195,000,000

FERC settlement recorded as preacquisition contingency

50,000,000

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in one year

38,000,000

Minimum future operating lease payments due in two years

38,000,000

Minimum future operating lease payments due in three years

38,000,000

Minimum future operating lease payments due in four years

36,000,000

Minimum future operating lease payments due in five years

36,000,000

Minimum future operating lease payments due beyond five years

367,000,000

Total minimum future operating lease payments

^[1]

553,000,000

Operating Leases Rent Expense [Abstract]

Lease And Rental Expense

^[2]

872,000,000

659,000,000

665,000,000

Operating Leases Rent Expense Footnote [Abstract]

Long Term Contract For Purchase Of Electric Power Capacity

801,000,000

630,000,000

641,000,000

Exelon Generation Co L L C [Member] | Net Capacity Purchases [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

^[3]

374,000,000

Purchase Obligations, Due within Two Years

^[3]

353,000,000

Purchase Obligations, Due within Three Years

^[3]

350,000,000

Purchase Obligations, Due within Four Years

^[3]

266,000,000

Purchase Obligations, Due within Five Years

^[3]

203,000,000

Purchase Obligations, Due after Five Years

^[3]

469,000,000

Purchase Obligations, Total

^[3]

2,015,000,000

Exelon Generation Co L L C [Member] | Power Purchases [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

^[4]

95,000,000

Purchase Obligations, Due within Two Years

^[4]

69,000,000

Purchase Obligations, Due within Three Years

^[4]

25,000,000

Purchase Obligations, Due within Four Years

^[4]

11,000,000

Purchase Obligations, Due within Five Years

^[4]

3,000,000

Purchase Obligations, Due after Five Years

^[4]

5,000,000

Purchase Obligations, Total

^[4]

208,000,000

Exelon Generation Co L L C [Member] | Transmission Rights Purchases [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

^[5]

28,000,000

Purchase Obligations, Due within Two Years

^[5]

26,000,000

Purchase Obligations, Due within Three Years

^[5]

13,000,000

Purchase Obligations, Due within Four Years

^[5]

2,000,000

Purchase Obligations, Due within Five Years

^[5]

2,000,000

Purchase Obligations, Due after Five Years

^[5]

34,000,000

Purchase Obligations, Total

^[5]

105,000,000

Exelon Generation Co L L C [Member] | Purchased Energy from Equity Investment [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

777,000,000

Purchase Obligations, Due within Two Years

516,000,000

Purchase Obligations, Due within Three Years

Purchase Obligations, Due within Four Years

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

1,293,000,000

Exelon Generation Co L L C [Member] | Total Unregulated Energy Commitments [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

1,274,000,000

Purchase Obligations, Due within Two Years

964,000,000

Purchase Obligations, Due within Three Years

388,000,000

Purchase Obligations, Due within Four Years

279,000,000

Purchase Obligations, Due within Five Years

208,000,000

Purchase Obligations, Due after Five Years

508,000,000

Purchase Obligations, Total

3,621,000,000

Exelon Generation Co L L C [Member] | Public Utilities, Inventory, Fuel [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

1,276,000,000

Purchase Obligations, Due within Two Years

1,207,000,000

Purchase Obligations, Due within Three Years

1,272,000,000

Purchase Obligations, Due within Four Years

976,000,000

Purchase Obligations, Due within Five Years

1,064,000,000

Purchase Obligations, Due after Five Years

3,062,000,000

Purchase Obligations, Total

8,857,000,000

Exelon Generation Co L L C [Member] | Solar Facility Construction [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

636,000,000

Exelon Generation Co L L C [Member] | Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

127,000,000

Purchase Obligations, Due within Two Years

120,000,000

Purchase Obligations, Due within Three Years

94,000,000

Purchase Obligations, Due within Four Years

32,000,000

Purchase Obligations, Due within Five Years

29,000,000

Purchase Obligations, Due after Five Years

85,000,000

Purchase Obligations, Total

487,000,000

Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

^[6]

1,841,000,000

Guarantee obligations maximum exposure next twelve months

^[6]

1,278,000,000

Guarantee obligations maximum exposure year two

^[6]

Guarantee obligations maximum exposure year three

^[6]

563,000,000

Guarantee obligations maximum exposure year four

^[6]

Guarantee obligations maximum exposure year five

^[6]

Guarantee obligations maximum exposure year six and beyond

^[6]

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

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

1,153,000,000

Guarantee obligations maximum exposure next twelve months

907,000,000

Guarantee obligations maximum exposure year two

203,000,000

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

43,000,000

Exelon Generation Co L L C [Member] | Energy Contract Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

1,794,000,000

Guarantee obligations maximum exposure next twelve months

1,794,000,000

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

Commercial Commitments Footnote [Abstract]

Estimated total assumed for commercial transaction obligations

1,500,000

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

Acquisition of interest in subsidiary

50.00%

Sale of interest in subsidiary

100.00%

Exelon Generation Co L L C [Member] | TEG And TEP Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

95,000,000

Sale of interest in subsidiary

49.50%

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

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

2,494,000,000

Guarantee obligations maximum exposure next twelve months

Guarantee obligations maximum exposure year two

Guarantee obligations maximum exposure year three

Guarantee obligations maximum exposure year four

Guarantee obligations maximum exposure year five

Guarantee obligations maximum exposure year six and beyond

2,494,000,000

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

Commercial Commitments Footnote [Abstract]

Guarantees in support of equity investment

211,000,000

Estimated net exposure for commercial transaction obligations

600,000

Exelon Generation Co L L C [Member] | Middle market lending commitment [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

180,000,000

Guarantee obligations maximum exposure next twelve months

180,000,000

Exelon Generation Co L L C [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

30,000,000

47,000,000

Exelon Generation Co L L C [Member] | Accrual For MGP Investigation And Remediation [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

Constellation Energy Nuclear Group LLC [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

689,000,000

Commonwealth Edison Co [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

230,000,000

Guarantee obligations maximum exposure next twelve months

30,000,000

Guarantee obligations maximum exposure year six and beyond

$ 200,000,000

Environmental Issues - MGP Site Contingency [Abstract]

Total number of MGP sites | MGPSites

Approved clean-up | MGPSites

Sites under study/remediation | MGPSites

MGP reserve update

$ 146,000,000

Number of sites related to portion of MGP reserve update | MGPSites

Portion of MGP reserve update

111,000,000

Environmental Issues - Solid and Hazardous Waste [Abstract]

Total cost of remediation to be shared by PRPs

$ 42,000,000

Continuous Power Interruption [Abstract]

Minimum number of customers ComEd can be held liable to for power interruption | Customers

30,000

Number of customers affected by a major storm | Customers

900,000

Number of customers porposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption | Customers

34,599

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in one year

^[7]

$ 13,000,000

Minimum future operating lease payments due in two years

^[7]

11,000,000

Minimum future operating lease payments due in three years

^[7]

11,000,000

Minimum future operating lease payments due in four years

^[7]

11,000,000

Minimum future operating lease payments due in five years

^[7]

6,000,000

Minimum future operating lease payments due beyond five years

^[7]

57,000,000

Total minimum future operating lease payments

^[7]

109,000,000

Future Operating Lease Payments Indefinite Periods Footnote [Abstract]

Future operating lease payments with indefinite periods due in one year

1,000,000

Future operating lease payments with indefinite periods due in two years

1,000,000

Future operating lease payments with indefinite periods due in three years

1,000,000

Future operating lease payments with indefinite periods due in four years

1,000,000

Future operating lease payments with indefinite periods due in five years

1,000,000

Operating Leases Rent Expense [Abstract]

Lease And Rental Expense

18,000,000

19,000,000

Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

367,000,000

Purchase Obligations, Due within Two Years

323,000,000

Purchase Obligations, Due within Three Years

136,000,000

Purchase Obligations, Due within Four Years

137,000,000

Purchase Obligations, Due within Five Years

140,000,000

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

1,103,000,000

Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

71,000,000

Purchase Obligations, Due within Two Years

73,000,000

Purchase Obligations, Due within Three Years

74,000,000

Purchase Obligations, Due within Four Years

76,000,000

Purchase Obligations, Due within Five Years

82,000,000

Purchase Obligations, Due after Five Years

1,285,000,000

Purchase Obligations, Total

1,661,000,000

Commonwealth Edison Co [Member] | Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

2,000,000

Purchase Obligations, Due within Two Years

6,000,000

Purchase Obligations, Due within Three Years

Purchase Obligations, Due within Four Years

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

8,000,000

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

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

22,000,000

Guarantee obligations maximum exposure next twelve months

22,000,000

Commonwealth Edison Co [Member] | Surety Bond [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

8,000,000

Guarantee obligations maximum exposure next twelve months

8,000,000

Commonwealth Edison Co [Member] | Performance Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

200,000,000

Guarantee obligations maximum exposure year six and beyond

200,000,000

Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

200,000,000

Commonwealth Edison Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

260,000,000

127,000,000

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

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

254,000,000

121,000,000

PECO Energy Co [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

203,000,000

Guarantee obligations maximum exposure next twelve months

25,000,000

Guarantee obligations maximum exposure year six and beyond

$ 178,000,000

Environmental Issues - MGP Site Contingency [Abstract]

Total number of MGP sites | MGPSites

Approved clean-up | MGPSites

Sites under study/remediation | MGPSites

MGP reserve update

$ 7,000,000

Dividend Payments Restrictions [Abstract]

Total of common stock and retained earnings

3,000,000,000

$ 3,000,000,000

Multiple of liquidating value of preferred stock

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in one year

^[7]

14,000,000

$ 14,000,000

14,000,000

$ 14,000,000

14,000,000

Minimum future operating lease payments due in two years

^[7]

13,000,000

Minimum future operating lease payments due in three years

^[7]

3,000,000

Minimum future operating lease payments due in four years

^[7]

3,000,000

Minimum future operating lease payments due in five years

^[7]

3,000,000

Minimum future operating lease payments due beyond five years

^[7]

Total minimum future operating lease payments

^[7]

36,000,000

Future Operating Lease Payments Indefinite Periods Footnote [Abstract]

Future operating lease payments with indefinite periods due in one year

3,000,000

Operating Leases Rent Expense [Abstract]

Lease And Rental Expense

27,000,000

28,000,000

31,000,000

PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

561,000,000

Purchase Obligations, Due within Two Years

200,000,000

Purchase Obligations, Due within Three Years

38,000,000

Purchase Obligations, Due within Four Years

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

799,000,000

PECO Energy Co [Member] | Alternative Energy Credits [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

12,000,000

Purchase Obligations, Due within Two Years

9,000,000

Purchase Obligations, Due within Three Years

2,000,000

Purchase Obligations, Due within Four Years

2,000,000

Purchase Obligations, Due within Five Years

2,000,000

Purchase Obligations, Due after Five Years

6,000,000

Purchase Obligations, Total

33,000,000

PECO Energy Co [Member] | Public Utilities, Inventory, Fuel [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

145,000,000

Purchase Obligations, Due within Two Years

87,000,000

Purchase Obligations, Due within Three Years

71,000,000

Purchase Obligations, Due within Four Years

49,000,000

Purchase Obligations, Due within Five Years

15,000,000

Purchase Obligations, Due after Five Years

77,000,000

Purchase Obligations, Total

444,000,000

PECO Energy Co [Member] | Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

17,000,000

Purchase Obligations, Due within Two Years

18,000,000

Purchase Obligations, Due within Three Years

1,000,000

Purchase Obligations, Due within Four Years

1,000,000

Purchase Obligations, Due within Five Years

1,000,000

Purchase Obligations, Due after Five Years

7,000,000

Purchase Obligations, Total

45,000,000

PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

22,000,000

Guarantee obligations maximum exposure next twelve months

22,000,000

PECO Energy Co [Member] | Surety Bond [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

3,000,000

Guarantee obligations maximum exposure next twelve months

3,000,000

PECO Energy Co [Member] | Performance Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

178,000,000

Guarantee obligations maximum exposure year six and beyond

178,000,000

PECO Energy Co [Member] | Trust Preferred Securities [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

178,000,000

PECO Energy Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

47,000,000

50,000,000

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

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

44,000,000

47,000,000

Baltimore Gas and Electric Company [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

254,000,000

Guarantee obligations maximum exposure next twelve months

4,000,000

Guarantee obligations maximum exposure year six and beyond

$ 250,000,000

Environmental Issues - MGP Site Contingency [Abstract]

Total number of MGP sites

13,000,000

Sites under study/remediation

3,000,000

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in one year

$ 12,000,000

Minimum future operating lease payments due in two years

10,000,000

Minimum future operating lease payments due in three years

9,000,000

Minimum future operating lease payments due in four years

7,000,000

Minimum future operating lease payments due in five years

6,000,000

Minimum future operating lease payments due beyond five years

29,000,000

Total minimum future operating lease payments

73,000,000

Future Operating Lease Payments Indefinite Periods Footnote [Abstract]

Future operating lease payments with indefinite periods due in one year

1,000,000

Operating Leases Rent Expense [Abstract]

Lease And Rental Expense

12,000,000

15,000,000

$ 13,000,000

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

68th Street and Sauer Dumps [Abstract]

Minimum estimated clean-up costs for all potentially responsible parties

50,000,000

Maximum estimated clean-up costs for all potentially responsible parties

64,000,000

Baltimore Gas and Electric Company [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

859,000,000

Purchase Obligations, Due within Two Years

467,000,000

Purchase Obligations, Due within Three Years

75,000,000

Purchase Obligations, Due within Four Years

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

1,401,000,000

Baltimore Gas and Electric Company [Member] | Curtailment Services [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

49,000,000

Purchase Obligations, Due within Two Years

47,000,000

Purchase Obligations, Due within Three Years

41,000,000

Purchase Obligations, Due within Four Years

16,000,000

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

153,000,000

Baltimore Gas and Electric Company [Member] | Public Utilities, Inventory, Fuel [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

133,000,000

Purchase Obligations, Due within Two Years

73,000,000

Purchase Obligations, Due within Three Years

54,000,000

Purchase Obligations, Due within Four Years

52,000,000

Purchase Obligations, Due within Five Years

52,000,000

Purchase Obligations, Due after Five Years

290,000,000

Purchase Obligations, Total

654,000,000

Baltimore Gas and Electric Company [Member] | Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

Purchase Obligations, Due within One Year

Purchase Obligations, Due within Two Years

Purchase Obligations, Due within Three Years

Purchase Obligations, Due within Four Years

Purchase Obligations, Due within Five Years

Purchase Obligations, Due after Five Years

Purchase Obligations, Total

Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

2,000,000

Guarantee obligations maximum exposure next twelve months

2,000,000

Baltimore Gas and Electric Company [Member] | Surety Bond [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

2,000,000

Guarantee obligations maximum exposure next twelve months

2,000,000

Baltimore Gas and Electric Company [Member] | Performance Guarantee [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

250,000,000

Guarantee obligations maximum exposure year six and beyond

250,000,000

Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]

Commercial Commitments [Abstract]

Guarantee Obligations Maximum Exposure

250,000,000

Baltimore Gas and Electric Company [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

1,000,000

Baltimore Gas and Electric Company [Member] | Accrual For MGP Investigation And Remediation [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrued environmental liabilities

$ 0

Midwest Generation, LLC [Member]

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Probable contingency (liability)

13,000,000

Midwest Generation's estimated environmental investigation and remediation costs

$ 9,000,000

Asbestos Loss Contingency [Abstract]

Asbestos liability reserve related to open claims

$ 13,000,000

[1]	Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments.
[2]	Includes Generation's PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation's PPAs and other capacity contracts totaled $801 million, $630 million and $641 million during 2012, 2011 and 2010, respectively.
[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 Generation's expected payments under these arrangements at December 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain capacity charges which are contingent on plant availability.
[4]	Power-Related Purchases include firm REC purchase agreements. 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]	Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[7]	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd's annual obligation for these arrangements, included in each of the years 2013 - 2017, was $1 million. PECO's annual obligation for these agreements, included in each of the years 2013 - 2017, was $3 million. BGE’s annual obligation for these agreements, included in each of the years 2013 - 2017, was $1 million. (c) Includes all future lease payments on a 99 year real estate lease that expires in 2105.

Supplemental Financial Information - Statement of Operations (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Operating revenues [Abstract]

Total operating revenues

$ 6,284,000

$ 6,565,000

$ 5,954,000

$ 4,686,000

$ 4,357,000

$ 5,254,000

$ 4,496,000

$ 4,956,000

$ 23,489,000

$ 19,063,000

$ 18,644,000

Taxes Excluding Income And Excise Taxes [Abstract]

Taxes other than income - utility

^[1]

463,000

443,000

476,000

Taxes other than income - real estate

227,000

177,000

175,000

Taxes other than income - payroll

131,000

123,000

121,000

Taxes other than income - other

198,000

42,000

36,000

Total taxes other than income

1,019,000

785,000

808,000

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

Total income (loss) in equity method investments

(91,000)

(1,000)

Decommissioning-Related Activities [Abstract]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[2]

189,000

177,000

176,000

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[2]

102,000

45,000

51,000

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

386,000

(74,000)

316,000

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

105,000

(4,000)

104,000

Net unrealized income (losses) on pledged assets

73,000

Regulatory offset to decommissioning trust fund-related activities

^[3]

(530,000)

130,000

(394,000)

Total decommissioning-related activities

325,000

62,000

253,000

Investment income

20,000

10,000

1,000

Long-term lease income

29,000

28,000

27,000

Interest income related to uncertain income tax positions

15,000

53,000

Losses on early retirement of debt

36,000

Other-than-temporary impairment to Rabbi trust investments

Credit facility termination fees

85,000

AFUDC - equity

17,000

11,000

Realized gains on Rabbi Trust investments

1,000

Other

25,000

(3,000)

19,000

Other, net

346,000

203,000

312,000

Exelon Generation Co L L C [Member]

Operating revenues [Abstract]

Total operating revenues

3,928,000

4,017,000

3,753,000

2,739,000

2,528,000

2,821,000

2,455,000

2,643,000

14,437,000

10,447,000

10,025,000

Taxes Excluding Income And Excise Taxes [Abstract]

Taxes other than income - utility

82,000

^[1]

27,000

Taxes other than income - real estate

189,000

146,000

142,000

Taxes other than income - payroll

78,000

71,000

70,000

Taxes other than income - other

20,000

18,000

Total taxes other than income

369,000

264,000

230,000

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

Total income (loss) in equity method investments

(91,000)

(1,000)

Decommissioning-Related Activities [Abstract]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[2]

189,000

177,000

176,000

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[2]

102,000

45,000

51,000

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

386,000

(74,000)

316,000

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

105,000

(4,000)

104,000

Net unrealized income (losses) on pledged assets

73,000

Regulatory offset to decommissioning trust fund-related activities

^[3]

(530,000)

130,000

(394,000)

Total decommissioning-related activities

325,000

62,000

253,000

Investment income

3,000

Interest income related to uncertain income tax positions

2,000

31,000

Losses on early retirement of debt

36,000

Credit facility termination fees

85,000

Other

(6,000)

(8,000)

4,000

Other, net

239,000

122,000

257,000

Commonwealth Edison Co [Member]

Operating revenues [Abstract]

Total operating revenues

1,290,000

1,484,000

1,281,000

1,388,000

1,362,000

1,784,000

1,444,000

1,466,000

5,443,000

6,056,000

6,204,000

Taxes Excluding Income And Excise Taxes [Abstract]

Taxes other than income - utility

^[1]

239,000

243,000

205,000

Taxes other than income - real estate

22,000

20,000

Taxes other than income - payroll

26,000

25,000

24,000

Taxes other than income - other

8,000

6,000

7,000

Total taxes other than income

295,000

296,000

256,000

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

Total income (loss) in equity method investments

Decommissioning-Related Activities [Abstract]

Investment income

1,000

Interest income related to uncertain income tax positions

20,000

14,000

6,000

Other-than-temporary impairment to Rabbi trust investments

AFUDC - equity

6,000

8,000

4,000

Realized gains on Rabbi Trust investments

1,000

Other

12,000

6,000

13,000

Other, net

39,000

29,000

24,000

PECO Energy Co [Member]

Operating revenues [Abstract]

Total operating revenues

790,000

806,000

715,000

875,000

778,000

946,000

842,000

1,153,000

3,186,000

3,720,000

5,519,000

Taxes Excluding Income And Excise Taxes [Abstract]

Taxes other than income - utility

^[1]

141,000

173,000

271,000

Taxes other than income - real estate

13,000

9,000

13,000

Taxes other than income - payroll

12,000

13,000

12,000

Taxes other than income - other

(4,000)

10,000

7,000

Total taxes other than income

162,000

205,000

303,000

Decommissioning-Related Activities [Abstract]

Investment income

2,000

3,000

1,000

Interest income related to uncertain income tax positions

1,000

AFUDC - equity

4,000

9,000

7,000

Other

2,000

1,000

Other, net

8,000

14,000

8,000

Baltimore Gas and Electric Company [Member]

Operating revenues [Abstract]

Total operating revenues

$ 703,000

$ 720,000

$ 616,000

$ 696,000

$ 673,000

$ 745,000

$ 674,000

$ 976,000

2,735,000

3,068,000

3,541,000

Taxes Excluding Income And Excise Taxes [Abstract]

Taxes other than income - utility

75,000

79,000

Taxes other than income - real estate

111,000

107,000

102,000

Taxes other than income - payroll

18,000

17,000

16,000

Taxes other than income - other

4,000

3,000

Total taxes other than income

208,000

207,000

200,000

Decommissioning-Related Activities [Abstract]

Investment income

11,000

13,000

15,000

AFUDC - equity

10,000

15,000

10,000

Other

2,000

(2,000)

Other, net

$ 23,000

$ 26,000

$ 25,000

[1]	Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations.
[2]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[3]	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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

Supplemental Financial Information - Cash Flow (Details) - USD ($)
$ in Thousands

12 Months Ended

37 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Depreciation, Amortization and Accretion [Abstract]

Property, plant and equipment

$ 1,712,000

$ 1,284,000

$ 1,144,000

Regulatory assets

129,000

63,000

931,000

Amortization of intangible assets, net

40,000

Amortization of energy contract assets and liabilities

1,110,000

Nuclear fuel

^[1]

848,000

755,000

672,000

Asset retirement obligation accretion

^[2]

240,000

214,000

196,000

Total depreciation, amortization and accretion

4,079,000

2,316,000

2,943,000

Cash Paid Refunded During Year [Abstract]

Interest (net of amount capitalized)

761,000

649,000

665,000

^[3]

Income taxes (net of refunds)

(171,000)

(457,000)

1,219,000

Other Non-Cash Operating Activities [Abstract]

Pension and non-pension postretirement benefits costs

820,000

542,000

581,000

Provision for uncollectible accounts

164,000

121,000

108,000

Provision for Obsolete Inventory

6,000

Stock-based compensation costs

94,000

67,000

44,000

Other Decommissioning Related Activity

145,000

(16,000)

^[4]

91,000

^[5]

Energy-related options

160,000

137,000

^[6]

(73,000)

^[7]

ARO adjustment

(19,000)

Amortization of regulatory asset related to debt costs

18,000

21,000

24,000

Amortization of rate stabilization deferral

57,000

Amortization of debt fair value adjustment

34,000

Accrual for Illinois utility distribution tax refund

(25,000)

APR SO2 allowances impairment

(57,000)

Discrete impacts from 2010 Rate Case Order

32,000

Discrete impacts from EIMA

96,000

82,000

^[8]

Merger related commitments

(141,000)

Severance Costs

(99,000)

Gain (loss) on equity method investments

91,000

1,000

Amortization of debt costs

(19,000)

Other

(11,000)

2,000

5,000

Total other noncash operating activities

(1,383,000)

Changes In Other Assets and Liabilities [Abstract]

Under/over-recovered energy and transmission costs

71,000

(45,000)

61,000

Other regulatory assets and liabilities

(404,000)

Other current assets and liabilities

213,000

Other noncurrent assets and liabilities

(248,000)

122,000

(99,000)

Total changes in other assets and liabilities

(368,000)

(24,000)

(56,000)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Change in ARC

781,000

186,000

(428,000)

Capital expenditures not paid

160,000

96,000

34,000

Purchase accounting adjustments

9,000

Merger with Constellation, common stock issued

7,365,000

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

103,000

51,000

Smart Grid Grant Reimbursements

113,000

56,000

Exelon Generation Co L L C [Member]

Depreciation, Amortization and Accretion [Abstract]

Property, plant and equipment

733,000

570,000

474,000

Regulatory assets

Amortization of intangible assets, net

35,000

Amortization of energy contract assets and liabilities

1,110,000

Nuclear fuel

^[1]

848,000

755,000

672,000

Asset retirement obligation accretion

240,000

214,000

^[2]

195,000

^[2]

Total depreciation, amortization and accretion

2,966,000

1,539,000

1,341,000

Cash Paid Refunded During Year [Abstract]

Interest (net of amount capitalized)

286,000

158,000

145,000

Income taxes (net of refunds)

175,000

347,000

732,000

Other Non-Cash Operating Activities [Abstract]

Pension and non-pension postretirement benefits costs

341,000

249,000

268,000

Provision for uncollectible accounts

22,000

1,000

Provision for Obsolete Inventory

6,000

$ 18,000

Other Decommissioning Related Activity

145,000

(16,000)

^[4]

91,000

^[5]

Energy-related options

160,000

137,000

^[6]

(73,000)

^[7]

ARO adjustment

(8,000)

Amortization of debt fair value adjustment

34,000

APR SO2 allowances impairment

(57,000)

Merger related commitments

(32,000)

Severance Costs

(34,000)

Gain (loss) on equity method investments

91,000

1,000

Amortization of debt costs

(11,000)

Other

19,000

55,000

16,000

Total other noncash operating activities

(537,000)

Changes In Other Assets and Liabilities [Abstract]

Other current assets and liabilities

(30,000)

Other noncurrent assets and liabilities

(98,000)

(34,000)

(29,000)

Total changes in other assets and liabilities

(128,000)

(57,000)

(45,000)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Change in ARC

781,000

186,000

(428,000)

Capital expenditures not paid

103,000

125,000

13,000

Purchase accounting adjustments

9,000

Merger with Constellation, common stock issued

5,264,000

Commonwealth Edison Co [Member]

Depreciation, Amortization and Accretion [Abstract]

Property, plant and equipment

525,000

502,000

473,000

Regulatory assets

80,000

52,000

43,000

Amortization of intangible assets, net

5,000

Nuclear fuel

Asset retirement obligation accretion

^[2]

1,000

^[2]

Total depreciation, amortization and accretion

610,000

554,000

517,000

Cash Paid Refunded During Year [Abstract]

Interest (net of amount capitalized)

288,000

296,000

283,000

Income taxes (net of refunds)

(42,000)

(676,000)

15,000

Other Non-Cash Operating Activities [Abstract]

Pension and non-pension postretirement benefits costs

282,000

213,000

215,000

Provision for uncollectible accounts

42,000

57,000

48,000

Provision for Obsolete Inventory

1,000

ARO adjustment

(10,000)

Amortization of regulatory asset related to debt costs

13,000

18,000

20,000

Accrual for Illinois utility distribution tax refund

(25,000)

Discrete impacts from 2010 Rate Case Order

32,000

Discrete impacts from EIMA

96,000

82,000

^[8]

Gain (loss) on equity method investments

Amortization of debt costs

(5,000)

Other

5,000

(4,000)

4,000

Total other noncash operating activities

(252,000)

Changes In Other Assets and Liabilities [Abstract]

Under/over-recovered energy and transmission costs

28,000

(49,000)

58,000

Other regulatory assets and liabilities

(68,000)

44,000

(19,000)

Other current assets and liabilities

(7,000)

Other noncurrent assets and liabilities

(95,000)

64,000

(184,000)

^[9]

Total changes in other assets and liabilities

(142,000)

45,000

(133,000)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Change in ARC

2,000

Capital expenditures not paid

15,000

7,000

PECO Energy Co [Member]

Depreciation, Amortization and Accretion [Abstract]

Property, plant and equipment

207,000

191,000

171,000

Regulatory assets

10,000

11,000

^[10]

889,000

^[10]

Nuclear fuel

Asset retirement obligation accretion

^[2]

Total depreciation, amortization and accretion

217,000

202,000

1,060,000

Cash Paid Refunded During Year [Abstract]

Interest (net of amount capitalized)

113,000

128,000

168,000

Income taxes (net of refunds)

(64,000)

(65,000)

433,000

Other Non-Cash Operating Activities [Abstract]

Pension and non-pension postretirement benefits costs

50,000

32,000

46,000

Provision for uncollectible accounts

60,000

64,000

59,000

ARO adjustment

(1,000)

Amortization of regulatory asset related to debt costs

3,000

4,000

Amortization of debt costs

(3,000)

Other

9,000

1,000

Total other noncash operating activities

(125,000)

Changes In Other Assets and Liabilities [Abstract]

Under/over-recovered energy and transmission costs

20,000

4,000

3,000

Other regulatory assets and liabilities

18,000

26,000

35,000

Other current assets and liabilities

(12,000)

Other noncurrent assets and liabilities

(10,000)

(4,000)

59,000

Total changes in other assets and liabilities

16,000

14,000

78,000

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Capital expenditures not paid

26,000

(35,000)

14,000

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

56,000

51,000

Smart Grid Grant Reimbursements

66,000

56,000

Baltimore Gas and Electric Company [Member]

Depreciation, Amortization and Accretion [Abstract]

Property, plant and equipment

245,000

224,000

214,000

Regulatory assets

53,000

50,000

35,000

Total depreciation, amortization and accretion

298,000

274,000

249,000

Cash Paid Refunded During Year [Abstract]

Interest (net of amount capitalized)

136,000

122,000

128,000

Income taxes (net of refunds)

(112,000)

(54,000)

(76,000)

Other Non-Cash Operating Activities [Abstract]

Pension and non-pension postretirement benefits costs

57,000

51,000

48,000

Provision for uncollectible accounts

44,000

38,000

Amortization of regulatory asset related to debt costs

2,000

Amortization of rate stabilization deferral

67,000

57,000

62,000

Deferral of storm costs

(16,000)

16,000

Merger related commitments

(27,000)

Amortization of debt costs

(2,000)

Other

(6,000)

(9,000)

(6,000)

Total other noncash operating activities

(193,000)

(129,000)

(144,000)

Changes In Other Assets and Liabilities [Abstract]

Under/over-recovered energy and transmission costs

26,000

(52,000)

6,000

Other regulatory assets and liabilities

(112,000)

10,000

(64,000)

Other current assets and liabilities

(7,000)

(88,000)

(7,000)

Other noncurrent assets and liabilities

8,000

(31,000)

2,000

Total changes in other assets and liabilities

(85,000)

(161,000)

(63,000)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Capital expenditures not paid

(4,000)

(7,000)

$ 28,000

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

47,000

23,000

Smart Grid Grant Reimbursements

$ 47,000

$ 41,000

[1]	Included in revenues or fuel expense on the Registrants' Consolidated Statements of Operations.
[2]	Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations.
[3]	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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
[4]	Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.
[5]	Excludes $167 million of interest paid to the IRS relating to a preliminary agreement reached during the third quarter of 2010. See Note 12 - Income Taxes for addition information.
[6]	In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 3 - Regulatory Matters for more information.
[7]	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 13 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
[8]	Includes the establishment of a regulatory asset, pursuant to EIMA, for the 2011 annual reconciliation in ComEd's distribution formula rate tariff and the deferral of costs associated with significant 2011 storms, partially offset by an accrual to fund a new Science and Technology Innovation Trust. See Note 3 - Regulatory Matters for more information.
[9]	Relates primarily to a decrease in interest payable associated with a change in uncertain income tax positions. See Note 12 - Income Taxes for additional information.
[10]	For PECO, primarily reflects CTC amortization.

Supplemental Financial Information - Balance Sheet (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Oct. 31, 2000

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

$ 45,000

Other Investments [Abstract]

Total investments

766,000

$ 3,055,000

Supplemental Financial Information Textuals [Abstract]

Payment to IRS

302,000

$ 302,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Estimated residual value of leased assets

1,492,000

$ 1,600,000

Less: unearned income

(836,000)

(807,000)

Net investment in long-term leases

656,000

685,000

Accrued Liabilities Current [Abstract]

Compensation-related accruals

^[1]

520,000

708,000

Taxes accrued

297,000

353,000

Interest accrued

192,000

236,000

Severance accrued

15,000

91,000

Other accrued expenses

231,000

412,000

^[2]

Total accrued expenses

1,255,000

1,800,000

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables

21,000

18,000

Property, Plant And Equipment [Abstract]

Accumulated depreciation

^[3]

10,959,000

12,184,000

Accumulated amortization of nuclear fuel

1,000

2,078,000

Accounts receivable, net

Allowance for uncollectible accounts

(199,000)

(293,000)

Accumulated Other Comprehensive Income (Loss) [Abstract]

Net unrealized gain (loss) on cash flow hedges

488,000

367,000

Pension and non-pension postretirement benefit plans

(2,938,000)

(3,155,000)

Accumulated unrealized gain (loss) on marketable securities

Accumulated other comprehensive income (loss), net

(2,450,000)

(2,767,000)

Capital Leases Net Investment In Direct Financing Leases [Member]

Other Investments [Abstract]

Other Investments

656,000

685,000

Trust For Benefit Of Employees [Member]

Other Investments [Abstract]

Other Investments

^[4]

65,000

100,000

Financing Trusts [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

^[5]

15,000

22,000

NuStart Energy Development [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

1,000

Keystone Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

13,000

38,000

Conemaugh Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

16,000

26,000

CENG [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

1,849,000

Safe Harbor [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

293,000

Malacha [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

8,000

Sacramento Solar [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

34,000

Exelon Generation Co L L C [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

30,000

2,247,000

Other Investments [Abstract]

Total investments

41,000

2,269,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term leases

693,000

Accrued Liabilities Current [Abstract]

Compensation-related accruals

^[1]

264,000

371,000

Taxes accrued

241,000

247,000

Interest accrued

56,000

60,000

Severance accrued

9,000

42,000

Other accrued expenses

209,000

396,000

^[2]

Total accrued expenses

779,000

1,116,000

Property, Plant And Equipment [Abstract]

Accumulated depreciation

^[6]

5,313,000

6,014,000

Accumulated amortization of nuclear fuel

1,784,000

Accounts receivable, net

Allowance for uncollectible accounts

(29,000)

(84,000)

Accumulated Other Comprehensive Income (Loss) [Abstract]

Net unrealized gain (loss) on cash flow hedges

915,000

513,000

Pension and non-pension postretirement benefit plans

(19,000)

Accumulated other comprehensive income (loss), net

915,000

513,000

Exelon Generation Co L L C [Member] | Trust For Benefit Of Employees [Member]

Other Investments [Abstract]

Other Investments

^[4]

11,000

22,000

Exelon Generation Co L L C [Member] | Financing Trusts [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

^[5]

Exelon Generation Co L L C [Member] | NuStart Energy Development [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

1,000

Exelon Generation Co L L C [Member] | Keystone Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

13,000

38,000

Exelon Generation Co L L C [Member] | Conemaugh Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

16,000

26,000

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

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

1,849,000

Exelon Generation Co L L C [Member] | Safe Harbor [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

293,000

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

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

8,000

Exelon Generation Co L L C [Member] | Sacramento Solar [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

33,000

Commonwealth Edison Co [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

6,000

Other Investments [Abstract]

Total investments

27,000

14,000

Accrued Liabilities Current [Abstract]

Compensation-related accruals

^[1]

127,000

125,000

Taxes accrued

59,000

61,000

Interest accrued

124,000

96,000

Severance accrued

2,000

4,000

Other accrued expenses

6,000

9,000

Total accrued expenses

318,000

295,000

Property, Plant And Equipment [Abstract]

Accumulated depreciation

2,750,000

2,998,000

Accounts receivable, net

Allowance for uncollectible accounts

(78,000)

(70,000)

Accumulated Other Comprehensive Income (Loss) [Abstract]

Net unrealized gain (loss) on cash flow hedges

Pension and non-pension postretirement benefit plans

Accumulated unrealized gain (loss) on marketable securities

(1,000)

Accumulated other comprehensive income (loss), net

(1,000)

Commonwealth Edison Co [Member] | Trust For Benefit Of Employees [Member]

Other Investments [Abstract]

Other Investments

^[4]

21,000

8,000

Commonwealth Edison Co [Member] | Financing Trusts [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

^[5]

6,000

Commonwealth Edison Co [Member] | NuStart Energy Development [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

Commonwealth Edison Co [Member] | Keystone Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

Commonwealth Edison Co [Member] | Conemaugh Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

PECO Energy Co [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

8,000

Other Investments [Abstract]

Total investments

30,000

Accrued Liabilities Current [Abstract]

Compensation-related accruals

^[1]

48,000

45,000

Taxes accrued

5,000

3,000

Interest accrued

27,000

32,000

Severance accrued

1,000

Other accrued expenses

2,000

1,000

Total accrued expenses

83,000

82,000

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(17,000)

(15,000)

Property, Plant And Equipment [Abstract]

Accumulated depreciation

2,662,000

2,797,000

Accounts receivable, net

Allowance for uncollectible accounts

(92,000)

(99,000)

Accumulated Other Comprehensive Income (Loss) [Abstract]

Net unrealized gain (loss) on cash flow hedges

Pension and non-pension postretirement benefit plans

Accumulated other comprehensive income (loss), net

1,000

PECO Energy Co [Member] | Low Risk [Member]

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(1,000)

PECO Energy Co [Member] | Medium Risk [Member]

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(3,000)

PECO Energy Co [Member] | High Risk [Member]

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(13,000)

(11,000)

PECO Energy Co [Member] | Trust For Benefit Of Employees [Member]

Other Investments [Abstract]

Other Investments

^[4]

22,000

PECO Energy Co [Member] | Financing Trusts [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

^[5]

8,000

PECO Energy Co [Member] | NuStart Energy Development [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

PECO Energy Co [Member] | Keystone Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

PECO Energy Co [Member] | Conemaugh Fuels [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

Baltimore Gas and Electric Company [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

8,000

Other Investments [Abstract]

Total investments

8,000

13,000

Accrued Liabilities Current [Abstract]

Compensation-related accruals

42,000

38,000

Taxes accrued

26,000

22,000

Interest accrued

41,000

Severance accrued

5,000

Other accrued expenses

1,000

Total accrued expenses

110,000

106,000

Property, Plant And Equipment [Abstract]

Accumulated depreciation

2,466,000

2,595,000

Accounts receivable, net

Allowance for uncollectible accounts

(37,000)

(40,000)

Baltimore Gas and Electric Company [Member] | Trust For Benefit Of Employees [Member]

Other Investments [Abstract]

Other Investments

5,000

Baltimore Gas and Electric Company [Member] | Financing Trusts [Member]

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Total equity method investments

$ 8,000

[1]	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
[2]	Includes $327 million and $184 million for amounts accrued related to Antelope Valley as of December 31, 2012 and December 31, 2011, respectively.
[3]	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.
[4]	The Registrants' investments in these marketable securities are recorded at fair market value.
[5]	Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the Consolidated Balance Sheets. See Note 1 - Significant Accounting Policies for additional information.
[6]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

Segment Information (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1]

$ 23,489,000

$ 19,063,000

$ 18,644,000

Intersegment revenues

^[2]

55,000

9,000

6,000

Revenues

$ 6,284,000

$ 6,565,000

$ 5,954,000

$ 4,686,000

$ 4,357,000

$ 5,254,000

$ 4,496,000

$ 4,956,000

23,489,000

19,063,000

18,644,000

Income (loss) from continuing operations before income taxes

1,798,000

3,956,000

4,221,000

Depreciation and amortization

1,881,000

1,347,000

2,075,000

Operating Expenses

^[1]

21,018,000

14,583,000

13,918,000

Interest Revenue (Expense), Net

928,000

726,000

817,000

Income taxes

627,000

1,457,000

1,658,000

Net income (loss)

1,171,000

2,499,000

2,563,000

Equity in earnings (losses) of unconsolidated affiliates

(91,000)

(1,000)

Capital expenditures

5,789,000

4,042,000

3,326,000

Total assets

78,554,000

54,995,000

78,554,000

54,995,000

Segment Reporting Additional Information [Abstract]

Utility taxes

^[3]

463,000

443,000

476,000

Unrealized Gain (Loss) on Derivatives

604,000

(291,000)

88,000

All Other Segments [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1],[4]

1,396,000

830,000

755,000

Intersegment revenues

^[4]

1,381,000

831,000

756,000

Income (loss) from continuing operations before income taxes

^[4]

(276,000)

(59,000)

(91,000)

Depreciation and amortization

^[4]

46,000

21,000

25,000

Operating Expenses

^[1],[4]

1,662,000

863,000

792,000

Interest Revenue (Expense), Net

^[4]

86,000

77,000

85,000

Income taxes

^[4]

(215,000)

9,000

(27,000)

Net income (loss)

^[4]

(61,000)

(68,000)

(64,000)

Capital expenditures

^[4]

67,000

42,000

14,000

Total assets

^[4]

10,432,000

6,147,000

10,432,000

6,147,000

Business Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1]

(3,064,000)

(1,990,000)

(3,859,000)

Intersegment revenues

^[2]

(3,042,000)

(1,990,000)

(3,859,000)

Income (loss) from continuing operations before income taxes

(56,000)

(13,000)

(8,000)

Depreciation and amortization

2,000

Operating Expenses

^[1]

(3,043,000)

(1,990,000)

(3,859,000)

Income taxes

(1,000)

(4,000)

(2,000)

Net income (loss)

(55,000)

(9,000)

(6,000)

Capital expenditures

^[5]

(78,000)

Total assets

(12,316,000)

(10,379,000)

(12,316,000)

(10,379,000)

Exelon Generation Co L L C [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1],[6]

14,437,000

10,447,000

10,025,000

Intersegment revenues

^[2],[6]

1,702,000

1,161,000

3,102,000

Income (loss) from continuing operations before income taxes

^[6]

1,058,000

2,827,000

3,150,000

Depreciation and amortization

^[6]

768,000

570,000

474,000

Operating Expenses

^[1],[6]

13,226,000

7,571,000

6,979,000

Interest Revenue (Expense), Net

^[6]

301,000

170,000

153,000

Income taxes

^[6]

500,000

1,056,000

1,178,000

Net income (loss)

^[6]

558,000

1,771,000

1,972,000

Equity in earnings (losses) of unconsolidated affiliates

^[6]

(91,000)

(1,000)

Capital expenditures

^[6]

3,554,000

2,491,000

1,883,000

Total assets

^[6]

40,681,000

27,433,000

40,681,000

27,433,000

Segment Reporting Additional Information [Abstract]

Utility taxes

82,000

27,000

Generation Mid Atlantic [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

5,038,000

4,052,000

3,232,000

Intersegment revenues

(44,000)

Revenues

^[7]

5,082,000

4,052,000

3,232,000

Revenue net of purchased power and fuel expense from external customers

3,477,000

3,350,000

2,501,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(44,000)

Revenue net of purchased power and fuel expense, Total

3,433,000

3,350,000

2,501,000

Generation Mid Atlantic [Member] | Baltimore Gas And Electric Company Affiliate [Member]

Segment Reporting Information [Line Items]

Intersegment revenues

322,000

Generation Mid Atlantic [Member] | PECO Energy Co Affiliate [Member]

Segment Reporting Information [Line Items]

Intersegment revenues

543,000

508,000

2,092,000

Generation Midwest [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

4,848,000

5,445,000

5,762,000

Intersegment revenues

24,000

Revenues

^[7]

4,824,000

5,445,000

5,762,000

Revenue net of purchased power and fuel expense from external customers

2,974,000

3,547,000

4,081,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

24,000

Revenue net of purchased power and fuel expense, Total

2,998,000

3,547,000

4,081,000

Generation Midwest [Member] | Commonwealth Edison Co Affiliate [Member]

Segment Reporting Information [Line Items]

Intersegment revenues

795,000

653,000

1,010,000

Segment Reporting Additional Information [Abstract]

Unrealized Gain (Loss) on Derivatives

7,000

Generation New England [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

1,093,000

11,000

14,000

Intersegment revenues

45,000

Revenues

^[7]

1,048,000

11,000

14,000

Revenue net of purchased power and fuel expense from external customers

151,000

9,000

11,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

45,000

Revenue net of purchased power and fuel expense, Total

196,000

9,000

11,000

Generation New York [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

557,000

Intersegment revenues

(25,000)

Revenues

^[7]

582,000

Revenue net of purchased power and fuel expense from external customers

101,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(25,000)

Revenue net of purchased power and fuel expense, Total

76,000

Generation ERCOT [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

1,367,000

575,000

543,000

Intersegment revenues

2,000

Revenues

^[7]

1,365,000

575,000

543,000

Revenue net of purchased power and fuel expense from external customers

403,000

84,000

(66,000)

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

2,000

Revenue net of purchased power and fuel expense, Total

405,000

84,000

(66,000)

Generation Other Regions [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[8]

833,000

201,000

149,000

Intersegment revenues

^[8]

78,000

Revenues

^[7],[8]

755,000

201,000

149,000

Revenue net of purchased power and fuel expense from external customers

^[8]

53,000

(14,000)

(65,000)

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

^[8]

78,000

Revenue net of purchased power and fuel expense, Total

^[8]

131,000

(14,000)

(65,000)

Generation Reportable Segments Total [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

13,736,000

10,284,000

9,700,000

Intersegment revenues

80,000

Revenues

^[7]

13,656,000

10,284,000

9,700,000

Revenue net of purchased power and fuel expense from external customers

7,159,000

6,976,000

6,462,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

80,000

Revenue net of purchased power and fuel expense, Total

7,239,000

6,976,000

6,462,000

Generation Total Consolidated Group [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

14,437,000

10,447,000

10,025,000

Intersegment revenues

Revenues

^[7]

14,437,000

10,447,000

10,025,000

Revenue net of purchased power and fuel expense from external customers

7,376,000

6,858,000

6,562,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

Revenue net of purchased power and fuel expense, Total

7,376,000

6,858,000

6,562,000

Generation All Other Segments [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[9]

701,000

163,000

325,000

Intersegment revenues

^[9]

(80,000)

Revenues

^[9]

781,000

163,000

325,000

Revenue net of purchased power and fuel expense from external customers

^[9]

217,000

(118,000)

100,000

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

^[9]

(80,000)

Revenue net of purchased power and fuel expense, Total

^[9]

137,000

(118,000)

100,000

Commonwealth Edison Co [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1]

5,443,000

6,056,000

6,204,000

Intersegment revenues

2,000

Income (loss) from continuing operations before income taxes

618,000

666,000

694,000

Depreciation and amortization

610,000

554,000

516,000

Operating Expenses

^[1]

4,557,000

5,074,000

5,148,000

Interest Revenue (Expense), Net

307,000

345,000

386,000

Income taxes

239,000

250,000

357,000

Net income (loss)

379,000

416,000

337,000

Capital expenditures

1,246,000

1,028,000

962,000

Total assets

22,905,000

22,638,000

22,905,000

22,638,000

Segment Reporting Additional Information [Abstract]

Utility taxes

243,000

205,000

Commonwealth Edison Co [Member] | Commonwealth Edison Co Affiliate [Member]

Segment Reporting Additional Information [Abstract]

Utility taxes

239,000

PECO Energy Co [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1]

3,186,000

3,720,000

5,519,000

Intersegment revenues

^[2]

3,000

5,000

Income (loss) from continuing operations before income taxes

508,000

535,000

476,000

Depreciation and amortization

217,000

202,000

1,060,000

Operating Expenses

^[1]

2,563,000

3,065,000

4,858,000

Interest Revenue (Expense), Net

123,000

134,000

193,000

Income taxes

127,000

146,000

152,000

Net income (loss)

381,000

389,000

324,000

Capital expenditures

422,000

481,000

545,000

Total assets

9,353,000

$ 9,156,000

9,353,000

9,156,000

Segment Reporting Additional Information [Abstract]

Utility taxes

141,000

$ 173,000

$ 271,000

Baltimore Gas and Electric Company [Member]

Segment Reporting Information [Line Items]

Segment Reporting Information, Revenue for Reportable Segment

^[1],[10]

2,091,000

Intersegment revenues

^[10]

9,000

Income (loss) from continuing operations before income taxes

^[10]

(54,000)

Depreciation and amortization

^[10]

238,000

Operating Expenses

^[1],[10]

2,053,000

Interest Revenue (Expense), Net

^[10]

111,000

Income taxes

^[10]

(23,000)

Net income (loss)

^[10]

(31,000)

Capital expenditures

^[10]

500,000

Total assets

^[10]

$ 7,499,000

7,499,000

Segment Reporting Additional Information [Abstract]

Utility taxes

$ 59,000

[1]	For the years ended December 31, 2012, 2011 and 2010, utility taxes of $82 million, $27 million and $0 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $239 million, $243 million and $205 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $141 million, $173 million and $271 million, respectively, are included in revenues and expenses for PECO. For the period of March 12, 2012 through December 31, 2012, utility taxes of $59 million are included in revenues and expenses for BGE.
[2]	The intersegment profit associated with Generation's sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.
[3]	Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations.
[4]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[5]	Represents capital projects transferred from BSC to Generation, ComEd and PECO. These projects are shown as capital expenditures at Generation, ComEd and PECO and the capital expenditure is eliminated upon consolidation.
[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 year ended December 31, 2012 include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the years ended December 31, 2011 and 2010 intersegment revenues for Generation include revenue from sales to PECO of $508 million and $2,092 million, respectively, in the Mid-Atlantic region, and sales to ComEd of $653 million and $1,010 million, respectively, in the Midwest region.
[7]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[8]	Other regions include the South, West and Canada, which are not considered individually significant.
[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 merger date.
[10]	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2012.

Related Party Transactions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Operating revenues from affiliates

$ 48,000

$ 9,000

$ 6,000

Total fuel purchases from related parties

922,000

137,000

144,000

Charitable contributions to Exelon Foundation

^[1]

7,000

10,000

Total interest expense to affiliates, net

25,000

Total income (loss) in equity method investments

(91,000)

(1,000)

Cash dividends paid to parent

1,716,000

1,393,000

1,389,000

Investments in affiliates

22,000

15,000

Total payables to affiliates (current)

88,000

5,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

Long-term debt to financing trusts

648,000

390,000

Impact Of Transactions Under Agreements [Abstract]

Amortization of energy contract assets and liabilities

$ 1,110,000

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

1.00%

ComEd Financing Three Affiliate [Member]

Total interest expense to affiliates, net

$ (13,000)

(13,000)

Investments in affiliates

6,000

Total payables to affiliates (current)

4,000

Long-term debt to financing trusts

206,000

Conemaugh Fuels LLC Affiliate [Member]

Total fuel purchases from related parties

68,000

69,000

70,000

Keystone Fuels LLC Affiliate [Member]

Total fuel purchases from related parties

61,000

68,000

74,000

NuStart Energy Development LLC Affiliate [Member]

Total income (loss) in equity method investments

Constellation Energy Nuclear Group Llc Affiliate [Member]

Operating revenues from affiliates

^[2]

42,000

Total fuel purchases from related parties

^[3]

793,000

Total receivables from affiliates (current)

^[2]

16,000

Total payables to affiliates (current)

^[3]

83,000

CENG Equity Investment Income Affiliate [Member]

Total income (loss) in equity method investments

73,000

Amortization Of Basis Difference In Ceng Affiliate [Member]

Total income (loss) in equity method investments

^[4]

(172,000)

Other Affiliate [Member]

Total interest expense to affiliates, net

Total income (loss) in equity method investments

8,000

(1,000)

PECO Energy Co Affiliate [Member]

Operating revenues from affiliates

^[5]

6,000

9,000

6,000

PECO Energy Capital Corporation Affiliate [Member]

Investments in affiliates

4,000

PECO Trust Three Affiliate [Member]

Total interest expense to affiliates, net

(6,000)

Total payables to affiliates (current)

1,000

Long-term debt to financing trusts

81,000

PECO Trust Four Affiliate [Member]

Total interest expense to affiliates, net

(6,000)

Investments in affiliates

4,000

5,000

Total payables to affiliates (current)

Long-term debt to financing trusts

103,000

BGE Capital Trust II [Member]

Investments in affiliates

8,000

Long-term debt to financing trusts

258,000

Exelon Generation Co L L C [Member]

Operating revenues from affiliates

1,702,000

1,161,000

3,102,000

Total fuel purchases from related parties

930,000

138,000

145,000

Operating and maintenance from affiliate

630,000

321,000

291,000

Total income (loss) in equity method investments

(91,000)

(1,000)

Cash distribution paid to member

1,626,000

172,000

1,508,000

Contributions from member

48,000

30,000

62,000

Mark-to-market derivative assets with affiliates

226,000

503,000

Total receivables from affiliates (current)

141,000

109,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

191,000

Total payables to affiliates (current)

193,000

58,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

Total payables to affiliates (noncurrent)

$ 2,397,000

2,222,000

Equity Method Investment Summarized Financial Information[Abstract]

Purchase of nuclear output by EDF (as a percent)

49.99%

Impact Of Transactions Under Agreements [Abstract]

Amortization of energy contract assets and liabilities

$ 1,110,000

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

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

50.01%

Basis difference in investment in CENG

$ 204,000

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

Operating revenues from affiliates

Operating and maintenance from affiliate

^[6]

625,000

314,000

285,000

Total payables to affiliates (current)

^[6]

77,000

51,000

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

Operating revenues from affiliates

^[7]

795,000

653,000

1,010,000

Total fuel purchases from related parties

Operating and maintenance from affiliate

^[8]

2,000

Mark-to-market derivative assets with affiliates

^[9]

226,000

503,000

Total receivables from affiliates (current)

^[7],[10]

54,000

70,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

^[9]

191,000

Total payables to affiliates (noncurrent)

^[11]

2,037,000

1,857,000

Swap Contract Receivable

53,000

Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member]

Total fuel purchases from related parties

68,000

69,000

70,000

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

Total receivable from affiliates (noncurrent)

1,000

Total payables to affiliates (current)

^[12]

33,000

7,000

Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member]

Total fuel purchases from related parties

61,000

68,000

74,000

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

Operating revenues from affiliates

^[13]

42,000

Total fuel purchases from related parties

^[14]

793,000

Operating and maintenance from affiliate

Total payables to affiliates (current)

^[14]

$ 83,000

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member] | Power Purchase Agreement [Member] | Minimum [Member]

Equity Method Investment Summarized Financial Information[Abstract]

Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent)

85.00%

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member] | Power Purchase Agreement [Member] | Maximum [Member]

Equity Method Investment Summarized Financial Information[Abstract]

Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent)

90.00%

Exelon Generation Co L L C [Member] | CENG Equity Investment Income Affiliate [Member]

Total income (loss) in equity method investments

$ 73,000

Exelon Generation Co L L C [Member] | Amortization Of Basis Difference In Ceng Affiliate [Member]

Total income (loss) in equity method investments

^[15]

(172,000)

Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member]

Operating revenues from affiliates

^[16]

543,000

508,000

2,092,000

Total fuel purchases from related parties

1,000

Operating and maintenance from affiliate

^[8]

3,000

5,000

4,000

Total receivables from affiliates (current)

^[16]

56,000

39,000

Total payables to affiliates (noncurrent)

^[11]

360,000

365,000

Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]

Operating revenues from affiliates

^[17]

322,000

Total fuel purchases from related parties

8,000

Total receivables from affiliates (current)

^[17]

31,000

Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member]

Total income (loss) in equity method investments

8,000

(1,000)

Commonwealth Edison Co [Member]

Operating revenues from affiliates

2,000

Purchased power from affiliate

789,000

653,000

1,010,000

Operating and maintenance from affiliate

163,000

158,000

152,000

Total interest expense to affiliates, net

13,000

15,000

13,000

Total income (loss) in equity method investments

Cash dividends paid to parent

105,000

300,000

310,000

Contributions from parent

2,000

Non cash contributions from parent

11,000

Intercompany non-cash allocation of tax benefit

11,000

Total receivable from affiliates (noncurrent)

2,039,000

1,860,000

Prepaid voluntary employee beneficiary association trust

^[18]

10,000

12,000

Investments in affiliates

6,000

Total payables to affiliates (current)

97,000

111,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

226,000

503,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

191,000

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

Operating and maintenance from affiliate

^[19]

163,000

158,000

152,000

Capitalized Costs

^[19]

92,000

85,000

84,000

Total payables to affiliates (current)

^[19]

35,000

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

Total interest expense to affiliates, net

13,000

Investments in affiliates

6,000

Total payables to affiliates (current)

4,000

Long-term debt to financing trusts

206,000

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

Total interest expense to affiliates, net

2,000

Total payables to affiliates (current)

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

Operating revenues from affiliates

2,000

Purchased power from affiliate

^[20]

789,000

653,000

1,010,000

Total receivable from affiliates (noncurrent)

^[21]

2,037,000

1,857,000

Total payables to affiliates (current)

^[20],[22]

54,000

70,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

^[23]

226,000

503,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

^[23]

191,000

Swap Contract Payable

53,000

Commonwealth Edison Co [Member] | Other Affiliate [Member]

Total receivable from affiliates (noncurrent)

2,000

3,000

Total payables to affiliates (current)

4,000

2,000

PECO Energy Co [Member]

Operating revenues from affiliates

3,000

5,000

Purchased power from affiliate

533,000

495,000

2,085,000

Operating and maintenance from affiliate

111,000

96,000

89,000

Total interest expense to affiliates, net

12,000

Cash dividends paid to parent

343,000

348,000

224,000

Contributions from parent

9,000

18,000

43,000

Repayment of receivable from parent

180,000

Total receivable from affiliates (noncurrent)

360,000

365,000

Prepaid voluntary employee beneficiary association trust

^[24]

2,000

3,000

Investments in affiliates

8,000

Total payables to affiliates (current)

76,000

62,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

Long-term debt to financing trusts

184,000

Shareholders' equity - receivable from parent

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

Operating and maintenance from affiliate

^[25]

107,000

92,000

89,000

Capitalized Costs

^[25]

54,000

60,000

40,000

Total payables to affiliates (current)

^[25]

18,000

21,000

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

Total payables to affiliates (current)

1,000

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

Operating revenues from affiliates

^[26]

3,000

5,000

Purchased power from affiliate

^[27]

533,000

495,000

2,085,000

Operating and maintenance from affiliate

4,000

Total receivable from affiliates (noncurrent)

^[28]

360,000

365,000

Total payables to affiliates (current)

^[27]

56,000

39,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

PECO Energy Co [Member] | Other Affiliate [Member]

Total interest expense to affiliates, net

PECO Energy Co [Member] | PECO Energy Capital Corporation Affiliate [Member]

Investments in affiliates

4,000

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

Total interest expense to affiliates, net

6,000

Total payables to affiliates (current)

1,000

Long-term debt to financing trusts

81,000

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

Total interest expense to affiliates, net

6,000

Investments in affiliates

4,000

Long-term debt to financing trusts

103,000

Baltimore Gas and Electric Company [Member]

Operating revenues from affiliates

10,000

8,000

7,000

Purchased power from affiliate

396,000

348,000

428,000

Operating and maintenance from affiliate

106,000

150,000

126,000

Cash dividends paid to parent

85,000

Contributions from parent

66,000

Investments in affiliates

8,000

Total payables to affiliates (current)

65,000

41,000

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

Operating and maintenance from affiliate

^[29]

106,000

150,000

126,000

Capitalized Costs

^[29]

21,000

29,000

49,000

Total payables to affiliates (current)

^[29]

12,000

Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member]

Total payables to affiliates (current)

3,000

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

Total payables to affiliates (current)

^[30]

17,000

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Operating revenues from affiliates

^[31]

10,000

8,000

7,000

Purchased power from affiliate

^[32]

396,000

348,000

$ 428,000

Total payables to affiliates (current)

^[32]

31,000

$ 41,000

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

Total payables to affiliates (current)

2,000

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]

Investments in affiliates

8,000

Long-term debt to financing trusts

$ 258,000

[1]	Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon
[2]	Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Under the SSA, BSC provides a variety of support services to CENG. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.
[3]	A subsidiary of Generation has an agreement under which it is purchasing 85-90% of the output of CENG’s nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG’s nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.
[4]	As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG. In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Through purchase accounting, Generation recorded the fair value of expected future distributions. Generation will record these distributions when realized as a reduction in its investment in CENG. Distributions realized in excess of the fair value recorded would be recorded in earnings in the period earned.
[5]	The intersegment profit associated with Generation's sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 - Regulatory Matters for additional information.
[6]	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[7]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information.
[8]	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
[9]	Represents the fair value of Generation's five-year financial swap contract with ComEd.
[10]	Generation had a $53 million and $53 million receivable from ComEd at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Instruments for additional information.
[11]	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 13 - Asset Retirement Obligations.
[12]	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.
[13]	Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Under the SSA, BSC provides a variety of support services to CENG. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.
[14]	A subsidiary of Generation has an agreement under which it is purchasing 85-90% of the output of CENG’s nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG’s nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.
[15]	As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG. In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Through purchase accounting, Generation recorded the fair value of expected future distributions. Generation will record these distributions when realized as a reduction in its investment in CENG. Distributions realized in excess of the fair value recorded would be recorded in earnings in the period earned.
[16]	Generation had a PPA with PECO to provide the full energy requirements to PECO through 2010. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information.
[17]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information.
[18]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd's contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[19]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[20]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Instruments for additional information.
[21]	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd's customers.
[22]	ComEd had a $53 million and $53 million payable to Generation at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 10 - Derivative Financial Information for additional information.
[23]	To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation.
[24]	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time.
[25]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[26]	PECO provides energy to Generation for Generation's own use.
[27]	PECO obtained all of its electric supply from Generation through 2010 under a PPA. Beginning January 1, 2011, PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs.
[28]	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers.
[29]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[30]	BGE receives a variety of corporate support services from Exelon Corporate, including payroll and benefits services.
[31]	BGE provides energy to Generation for Generation's own use.
[32]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information

Quarterly Data (Details) - USD ($)
$ / shares in Units, shares in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Earnings Per Share Basic [Abstract]

Average common shares outstanding - basic

854,000

853,000

705,000

664,000

663,000

662,000

816,000

663,000

661,000

Earnings Per Share, Basic

$ 0.44

$ 0.35

$ 0.34

$ 0.28

$ 0.91

$ 0.93

$ 1.01

Earnings Per Share Diluted

Average common shares outstanding - diluted

857,000

856,000

707,000

666,000

665,000

664,000

819,000

665,000

663,000

Earnings Per Share, Diluted

$ 0.44

$ 0.35

$ 0.33

$ 0.28

$ 0.91

$ 0.90

$ 0.93

$ 1.01

$ 1.42

$ 3.75

$ 3.87

Selected Quarterly Financial Information [Line Items]

Revenues

$ 6,284,000,000

$ 6,565,000,000

$ 5,954,000,000

$ 4,686,000,000

$ 4,357,000,000

$ 5,254,000,000

$ 4,496,000,000

$ 4,956,000,000

$ 23,489,000,000

$ 19,063,000,000

$ 18,644,000,000

Operating Income (Loss)

704,000,000

603,000,000

714,000,000

359,000,000

1,062,000,000

1,181,000,000

1,034,000,000

1,202,000,000

2,380,000,000

4,479,000,000

4,726,000,000

Net Income Loss

378,000,000

296,000,000

286,000,000

200,000,000

606,000,000

601,000,000

620,000,000

668,000,000

1,171,000,000

2,499,000,000

2,563,000,000

Share Price And Dividend [Abstract]

High Price

37.50

39.82

39.37

43.70

45.45

45.27

42.89

43.58

37.50

45.45

Low Price

28.40

34.54

36.27

38.31

39.93

39.51

39.53

39.06

28.40

39.93

$ 29.74

$ 35.58

$ 37.62

$ 39.21

$ 43.37

$ 42.61

$ 42.84

$ 41.24

$ 29.74

$ 43.37

Dividends

$ 0.525

^[1]

$ 0.525

^[1]

Exelon Generation Co L L C [Member]

Selected Quarterly Financial Information [Line Items]

Revenues

$ 3,928,000,000

$ 4,017,000,000

$ 3,753,000,000

$ 2,739,000,000

$ 2,528,000,000

$ 2,821,000,000

$ 2,455,000,000

$ 2,643,000,000

$ 14,437,000,000

$ 10,447,000,000

10,025,000,000

Operating Income (Loss)

290,000,000

174,000,000

384,000,000

272,000,000

673,000,000

754,000,000

647,000,000

801,000,000

1,120,000,000

2,875,000,000

3,046,000,000

Net Income Loss

137,000,000

91,000,000

166,000,000

168,000,000

447,000,000

386,000,000

443,000,000

495,000,000

558,000,000

1,771,000,000

1,972,000,000

Commonwealth Edison Co [Member]

Selected Quarterly Financial Information [Line Items]

Revenues

1,290,000,000

1,484,000,000

1,281,000,000

1,388,000,000

1,362,000,000

1,784,000,000

1,444,000,000

1,466,000,000

5,443,000,000

6,056,000,000

6,204,000,000

Operating Income (Loss)

300,000,000

218,000,000

142,000,000

226,000,000

285,000,000

243,000,000

254,000,000

200,000,000

886,000,000

982,000,000

1,056,000,000

Net Income Loss

160,000,000

90,000,000

42,000,000

87,000,000

121,000,000

112,000,000

114,000,000

69,000,000

379,000,000

416,000,000

337,000,000

PECO Energy Co [Member]

Selected Quarterly Financial Information [Line Items]

Revenues

790,000,000

806,000,000

715,000,000

875,000,000

778,000,000

946,000,000

842,000,000

1,153,000,000

3,186,000,000

3,720,000,000

5,519,000,000

Operating Income (Loss)

117,000,000

178,000,000

151,000,000

177,000,000

131,000,000

153,000,000

161,000,000

210,000,000

623,000,000

655,000,000

661,000,000

Net Income Loss

79,000,000

122,000,000

79,000,000

96,000,000

73,000,000

104,000,000

82,000,000

125,000,000

381,000,000

389,000,000

324,000,000

Baltimore Gas and Electric Company [Member]

Selected Quarterly Financial Information [Line Items]

Revenues

703,000,000

720,000,000

616,000,000

696,000,000

673,000,000

745,000,000

674,000,000

976,000,000

2,735,000,000

3,068,000,000

3,541,000,000

Operating Income (Loss)

61,000,000

30,000,000

52,000,000

(11,000,000)

84,000,000

23,000,000

54,000,000

153,000,000

132,000,000

314,000,000

350,000,000

Net Income Loss

$ 15,000,000

$ (4,000,000)

$ 13,000,000

$ (33,000,000)

$ 34,000,000

$ (2,000,000)

$ 13,000,000

$ 78,000,000

$ 4,000,000

$ 136,000,000

$ 147,000,000

[1]

The fourth quarter 2011 dividend does not include the first quarter 2012 regular quarterly dividend of $0.525 per share, declared by the Exelon Board of Directors on October 25, 2011. The first quarter 2012 dividend is payable on March 9, 2012, to shareholders of record of Exelon at the end of the day on February 15, 2012.

Label

Element

Value

Rate Stabilization Deferral [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

$ 67,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

225,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Deferred Storm Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

DSP Program costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

Fair Value Of Long Term Debt [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[1]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

256,000,000

^[1]

Pension and Other Postretirement Benefits [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

304,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

204,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

3,673,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,794,000,000

DSP II Program Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Energy Efficiency And Demand Response Programs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

56,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

126,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Other Regulatory Assets [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

23,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

17,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

Fair Value Of Supply Contract [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

77,000,000

^[2]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

12,000,000

^[2]

Under Recovered Universal Service Fund Costs Member [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

11,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Under Recovered Energy And Transmission Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

43,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

57,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Under Recovered Distribution Service Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

18,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

191,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

70,000,000

Electric Generation Related Regulatory Asset [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

16,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

40,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

RTO Startup Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

4,000,000

Financial Swap with Generation [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

AMI Expenses [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

70,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

28,000,000

Renewable Energy And Associated REC [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

18,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

49,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

97,000,000

AMI Meter Events [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

17,000,000

DSP Program Electric Procurement Contracts [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Asset Retirement Obligations [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

90,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

74,000,000

MGP Remediation Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

58,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

30,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

232,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

129,000,000

Deferred Income Taxes [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

5,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

1,382,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

1,176,000,000

Debt Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

18,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

68,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

81,000,000

Severance [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

29,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

25,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

28,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

38,000,000

Common Electric And Gas T And D Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,029,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

564,000,000

Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,926,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,110,000,000

Other Capitalized Property Plant And Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

912,000,000

^[3]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

439,000,000

^[3]

Gas Distribution Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

3,108,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,793,000,000

Electric Generation Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

19,004,000,000

^[4]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

13,682,000,000

^[4]

Nuclear Fuel [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

4,815,000,000

^[5]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

4,225,000,000

^[5]

Electric Transmission And Distribution [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

26,576,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

21,716,000,000

Commonwealth Edison Co [Member] | Rate Stabilization Deferral [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Deferred Storm Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | DSP Program costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Fair Value Of Long Term Debt [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[1]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[1]

Commonwealth Edison Co [Member] | Pension and Other Postretirement Benefits [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | DSP II Program Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Other Regulatory Assets [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

16,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

13,000,000

Commonwealth Edison Co [Member] | Fair Value Of Supply Contract [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[2]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[2]

Commonwealth Edison Co [Member] | Under Recovered Universal Service Fund Costs Member [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

48,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

18,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

14,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

191,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

70,000,000

Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | RTO Startup Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

4,000,000

Commonwealth Edison Co [Member] | Financial Swap with Generation [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

226,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

503,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

191,000,000

Commonwealth Edison Co [Member] | AMI Expenses [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

10,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

Commonwealth Edison Co [Member] | Renewable Energy And Associated REC [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

18,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

49,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

97,000,000

Commonwealth Edison Co [Member] | AMI Meter Events [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Net Regulatory Asset

exc_NetRegulatoryAsset

209,000,000

Net Regulatory Asset

exc_NetRegulatoryAsset

84,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

65,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

50,000,000

Commonwealth Edison Co [Member] | MGP Remediation Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

51,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

24,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

197,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

91,000,000

Commonwealth Edison Co [Member] | Deferred Income Taxes [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

5,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

5,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

62,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

66,000,000

Commonwealth Edison Co [Member] | Debt Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

11,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

15,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

62,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

73,000,000

Commonwealth Edison Co [Member] | Severance [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

25,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

25,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

12,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

38,000,000

Commonwealth Edison Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

294,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

187,000,000

Commonwealth Edison Co [Member] | Other Capitalized Property Plant And Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

50,000,000

^[6]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

47,000,000

^[6]

Commonwealth Edison Co [Member] | Electric Transmission And Distribution [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

16,480,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

15,637,000,000

PECO Energy Co [Member] | Rate Stabilization Deferral [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Deferred Storm Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | DSP Program costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

PECO Energy Co [Member] | Fair Value Of Long Term Debt [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[1]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[1]

PECO Energy Co [Member] | Pension and Other Postretirement Benefits [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

7,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | DSP II Program Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Other Regulatory Assets [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

8,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

8,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

12,000,000

PECO Energy Co [Member] | Fair Value Of Supply Contract [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[2]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[2]

PECO Energy Co [Member] | Under Recovered Universal Service Fund Costs Member [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

11,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | RTO Startup Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Financial Swap with Generation [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | AMI Expenses [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

29,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

22,000,000

PECO Energy Co [Member] | Renewable Energy And Associated REC [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | AMI Meter Events [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

17,000,000

PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

PECO Energy Co [Member] | Asset Retirement Obligations [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

24,000,000

PECO Energy Co [Member] | MGP Remediation Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

6,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

6,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

33,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

38,000,000

PECO Energy Co [Member] | Deferred Income Taxes [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

1,255,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

1,110,000,000

PECO Energy Co [Member] | Debt Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

8,000,000

PECO Energy Co [Member] | Severance [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

568,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

564,000,000

PECO Energy Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

76,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

83,000,000

PECO Energy Co [Member] | Other Capitalized Property Plant And Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

17,000,000

^[7]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

17,000,000

^[7]

PECO Energy Co [Member] | Gas Distribution Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,859,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,793,000,000

PECO Energy Co [Member] | Electric Transmission And Distribution [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

6,355,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

6,079,000,000

Exelon Generation Co L L C [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,352,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

827,000,000

Exelon Generation Co L L C [Member] | Other Capitalized Property Plant And Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

374,000,000

^[8]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

54,000,000

^[8]

Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

19,004,000,000

^[9]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

13,682,000,000

^[9]

Exelon Generation Co L L C [Member] | Nuclear Fuel [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

4,815,000,000

^[10]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

4,225,000,000

^[10]

Exelon Generation Co L L C [Member] | Operating Revenue [Member]

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

(362,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

87,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

67,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(209,000,000)

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

429,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(296,000,000)

Exelon Generation Co L L C [Member] | Operating Revenue [Member] | Pro Forma [Member]

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

258,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(258,000,000)

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(516,000,000)

Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

215,000,000

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

131,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

453,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

238,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(219,000,000)

Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | Pro Forma [Member]

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

(40,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

389,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(39,000,000)

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

85,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

1,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(304,000,000)

Other Segment [Member] | Operating Revenue [Member] | Business Intersegment Eliminations [Member]

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

(94,000,000)

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

7,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

101,000,000

Baltimore Gas and Electric Company [Member] | Rate Stabilization Deferral [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

67,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

63,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

225,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

295,000,000

Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

Baltimore Gas and Electric Company [Member] | DSP Program costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Fair Value Of Long Term Debt [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[1]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[1]

Baltimore Gas and Electric Company [Member] | Pension and Other Postretirement Benefits [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

3,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | DSP II Program Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

56,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

29,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

126,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

95,000,000

Baltimore Gas and Electric Company [Member] | Other Regulatory Assets [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Fair Value Of Supply Contract [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

^[2]

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

^[2]

Baltimore Gas and Electric Company [Member] | Under Recovered Universal Service Fund Costs Member [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

28,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

50,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

16,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

16,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

40,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

56,000,000

Baltimore Gas and Electric Company [Member] | RTO Startup Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Financial Swap with Generation [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | AMI Expenses [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

31,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

15,000,000

Baltimore Gas and Electric Company [Member] | Renewable Energy And Associated REC [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | AMI Meter Events [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | DSP Program Electric Procurement Contracts [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | MGP Remediation Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Baltimore Gas and Electric Company [Member] | Deferred Income Taxes [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

9,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

8,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

65,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

68,000,000

Baltimore Gas and Electric Company [Member] | Debt Costs [Member]

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

1,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

2,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

10,000,000

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

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

4,000,000

Regulatory Assets Current

us-gaap_RegulatoryAssetsCurrent

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

16,000,000

Regulatory Assets, Noncurrent

us-gaap_RegulatoryAssetsNoncurrent

1,000,000

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

415,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 554,000,000

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

50 years

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

5 years

Baltimore Gas and Electric Company [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 193,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 298,000,000

Baltimore Gas and Electric Company [Member] | Other Capitalized Property Plant And Equipment [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

20 years

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 31,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

15,000,000

Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

1,387,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 1,548,000,000

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

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

90 years

Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | Minimum [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

5 years

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member]

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 5,483,000,000

Property Plant And Equipment Gross

us-gaap_PropertyPlantAndEquipmentGross

$ 5,767,000,000

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member] | Maximum [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

90 years

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member] | Minimum [Member]

Property, Plant and Equipment, Useful Life

us-gaap_PropertyPlantAndEquipmentUsefulLife

5 years

Goodwill Accumulated Impairment Losses [Member] | Commonwealth Edison Co [Member]

Goodwill

us-gaap_Goodwill

$ 1,983,000,000

Goodwill Gross [Member] | Commonwealth Edison Co [Member]

Goodwill

us-gaap_Goodwill

$ 4,608,000,000

[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. See Note 4 – Merger and Acquisitions for additional information.
[2]	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved regulated rates. See Note 4 – Merger and Acquisitions for additional information.
[3]	Includes Generation's buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively. Also includes land held for future use and non utility property at ComEd, PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation.
[4]	Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.
[5]	Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.
[6]	Represents land held for future use and non utility property.
[7]	Represents land held for future use and non utility property.
[8]	Includes buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively.
[9]	Includes assets acquired through acquisitions. See Note 4 – Mergers and Acquisitions for additional information.
[10]	Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.