View Filing Data

Cash and cash equivalents of variable interest entities

$ 1,602,000,000

$ 1,016,000,000

98,000,000

Restricted cash and investments

73,000,000

40,000,000

Restricted cash and investments of variable interest entity

67,000,000

2,835,000,000

1,613,000,000

Accounts receivable of variable interest entities

1,216,000,000

1,000,000,000

225,000,000

928,000,000

432,000,000

1,141,000,000

13,000,000

264,000,000

208,000,000

767,000,000

656,000,000

254,000,000

786,000,000

390,000,000

1,072,000,000

345,000,000

11,328,000,000

5,713,000,000

43,914,000,000

32,570,000,000

Nuclear decommissioning trust funds

6,192,000,000

4,518,000,000

7,140,000,000

6,507,000,000

838,000,000

751,000,000

371,000,000

15,000,000

Investment in CENG

1,908,000,000

Goodwill

2,625,000,000

1,039,000,000

650,000,000

631,000,000

734,000,000

1,191,000,000

388,000,000

1,176,000,000

524,000,000

23,111,000,000

16,712,000,000

78,353,000,000

54,995,000,000

Short-term notes payable - accounts receivable agreement

Short-term borrowings

60,000,000

163,000,000

225,000,000

Long-term debt of variable interest entities due within one year

1,049,000,000

828,000,000

70,000,000

Accounts payable of variable interest entities

2,359,000,000

1,444,000,000

132,000,000

1,502,000,000

1,255,000,000

52,000,000

1,000,000

299,000,000

197,000,000

Dividends payable

4,000,000

349,000,000

Mark-to-market derivative liabilities with affiliate

521,000,000

112,000,000

523,000,000

974,000,000

560,000,000

7,770,000,000

5,134,000,000

17,050,000,000

11,799,000,000

Long-term debt of variable interest entity

649,000,000

390,000,000

546,000,000

Deferred income taxes and unamortized investment tax credits

11,600,000,000

8,253,000,000

4,866,000,000

3,884,000,000

Pension obligations

2,575,000,000

2,194,000,000

Spent nuclear fuel obligation

2,946,000,000

2,263,000,000

1,020,000,000

1,019,000,000

4,000,000,000

3,627,000,000

Mark-to-market derivative liabilities with affiliate

407,000,000

126,000,000

Payable for Zion Station decommissioning

621,000,000

422,000,000

563,000,000

1,691,000,000

1,268,000,000

30,148,000,000

23,197,000,000

56,163,000,000

40,520,000,000

Preferred securities

87,000,000

Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively)

16,594,000,000

9,107,000,000

(2,327,000,000)

9,959,000,000

10,055,000,000

(2,405,000,000)

(2,450,000,000)

BGE preference stock not subject to mandatory redemption

21,821,000,000

14,385,000,000

193,000,000

89,000,000

3,000,000

Total equity

22,103,000,000

14,388,000,000

78,353,000,000

54,995,000,000

(2,405,000,000)

(2,450,000,000)

89,000,000

3,000,000

Removal Costs [Member]

94,000,000

61,000,000

Customer Rate Credit [Member]

1,397,000,000

1,185,000,000

1,000,000

Cash and cash equivalents of variable interest entities

732,000,000

496,000,000

98,000,000

Restricted cash and cash equivalents

1,000,000

5,000,000

Restricted cash and investments of variable interest entity

19,000,000

1,580,000,000

578,000,000

Accounts receivable of variable interest entities

291,000,000

257,000,000

225,000,000

928,000,000

432,000,000

Receivables from affiliates

352,000,000

^[1]

503,000,000

^[2]

130,000,000

109,000,000

1,141,000,000

13,000,000

136,000,000

120,000,000

620,000,000

556,000,000

905,000,000

148,000,000

7,158,000,000

3,217,000,000

18,708,000,000

13,475,000,000

Nuclear decommissioning trust funds

7,140,000,000

6,507,000,000

82,000,000

41,000,000

348,000,000

1,000,000

Investment in CENG

1,908,000,000

1,026,000,000

635,000,000

191,000,000

^[2]

2,021,000,000

2,068,000,000

631,000,000

734,000,000

1,191,000,000

388,000,000

877,000,000

176,000,000

15,224,000,000

10,741,000,000

41,090,000,000

27,433,000,000

Short-term borrowings

11,000,000

2,000,000

Long-term debt of variable interest entities due within one year

23,000,000

3,000,000

4,000,000

Accounts payable of variable interest entities

1,501,000,000

753,000,000

132,000,000

1,106,000,000

779,000,000

99,000,000

58,000,000

69,000,000

244,000,000

Mark-to-market derivative liabilities with affiliate

504,000,000

103,000,000

429,000,000

377,000,000

202,000,000

4,255,000,000

2,144,000,000

Long-term debt of variable interest entity

7,148,000,000

3,674,000,000

208,000,000

Deferred income taxes and unamortized investment tax credits

5,410,000,000

3,966,000,000

4,730,000,000

3,767,000,000

Spent nuclear fuel obligation

849,000,000

703,000,000

1,020,000,000

1,019,000,000

2,383,000,000

2,222,000,000

Mark-to-market derivative liabilities with affiliate

355,000,000

29,000,000

Payable for Zion Station decommissioning

589,000,000

422,000,000

563,000,000

791,000,000

638,000,000

16,549,000,000

12,907,000,000

28,160,000,000

18,725,000,000

752,000,000

915,000,000

91,000,000

5,000,000

Membership interest

8,814,000,000

3,556,000,000

Undistributed earnings

3,273,000,000

4,232,000,000

752,000,000

915,000,000

Total member's equity

12,839,000,000

8,703,000,000

Total liabilities and equity

91,000,000

5,000,000

Total equity

12,930,000,000

8,708,000,000

41,090,000,000

27,433,000,000

Restricted cash and cash equivalents

31,000,000

234,000,000

3,000,000

602,000,000

655,000,000

274,000,000

385,000,000

Inventories, net

92,000,000

81,000,000

Counterparty collateral deposited

87,000,000

61,000,000

90,000,000

511,000,000

657,000,000

27,000,000

22,000,000

1,624,000,000

2,188,000,000

13,611,000,000

13,121,000,000

589,000,000

699,000,000

9,000,000

21,000,000

Receivable from affiliate

6,000,000

Goodwill

2,625,000,000

2,024,000,000

1,860,000,000

1,698,000,000

1,803,000,000

285,000,000

315,000,000

7,236,000,000

7,329,000,000

22,471,000,000

22,638,000,000

Short-term borrowings

35,000,000

252,000,000

450,000,000

326,000,000

325,000,000

220,000,000

318,000,000

84,000,000

111,000,000

Customer deposits

137,000,000

136,000,000

172,000,000

137,000,000

Mark-to-market derivative liabilities with affiliate

17,000,000

9,000,000

352,000,000

503,000,000

128,000,000

82,000,000

1,723,000,000

2,071,000,000

4,965,000,000

5,215,000,000

206,000,000

Deferred income taxes and unamortized investment tax credits

4,201,000,000

3,993,000,000

99,000,000

89,000,000

359,000,000

271,000,000

3,206,000,000

3,042,000,000

Mark-to-market derivative liabilities with affiliate

53,000,000

97,000,000

191,000,000

484,000,000

426,000,000

8,402,000,000

8,109,000,000

15,296,000,000

15,601,000,000

1,588,000,000

Other paid-in capital

5,016,000,000

5,003,000,000

571,000,000

447,000,000

(1,000,000)

7,175,000,000

7,037,000,000

22,471,000,000

22,638,000,000

Commonwealth Edison Co [Member] | Removal Costs [Member]

(1,000,000)

73,000,000

61,000,000

Commonwealth Edison Co [Member] | Customer Rate Credit [Member]

1,185,000,000

Restricted cash and cash equivalents

648,000,000

194,000,000

$ 518,000,000

$ 522,000,000

2,000,000

294,000,000

380,000,000

240,000,000

376,000,000

75,000,000

87,000,000

20,000,000

18,000,000

Receivable from Exelon intercompany money pool

39,000,000

25,000,000

77,000,000

82,000,000

Prepaid utility taxes

57,000,000

1,000,000

42,000,000

39,000,000

38,000,000

39,000,000

1,530,000,000

1,243,000,000

5,996,000,000

5,874,000,000

1,323,000,000

1,216,000,000

23,000,000

22,000,000

Receivable from affiliate

8,000,000

362,000,000

365,000,000

378,000,000

382,000,000

41,000,000

46,000,000

2,135,000,000

2,039,000,000

9,661,000,000

9,156,000,000

Short-term notes payable - accounts receivable agreement

225,000,000

375,000,000

200,000,000

262,000,000

87,000,000

83,000,000

76,000,000

62,000,000

Customer deposits

51,000,000

53,000,000

Mark-to-market derivative liabilities with affiliate

105,000,000

60,000,000

26,000,000

25,000,000

1,145,000,000

1,947,000,000

1,597,000,000

184,000,000

Deferred income taxes and unamortized investment tax credits

2,281,000,000

2,170,000,000

29,000,000

28,000,000

310,000,000

288,000,000

582,000,000

585,000,000

118,000,000

134,000,000

3,320,000,000

3,205,000,000

6,596,000,000

6,131,000,000

Preferred securities

87,000,000

2,379,000,000

598,000,000

559,000,000

1,000,000

2,978,000,000

2,938,000,000

9,661,000,000

9,156,000,000

PECO Energy Co [Member] | Removal Costs [Member]

1,000,000

PECO Energy Co [Member] | Customer Rate Credit [Member]

Restricted cash and investments of variable interest entity

121,000,000

49,000,000

$ 51,000,000

$ 50,000,000

49,000,000

30,000,000

358,000,000

428,000,000

120,000,000

90,000,000

Income taxes receivable

61,000,000

21,000,000

53,000,000

74,000,000

34,000,000

Prepaid utility taxes

85,000,000

56,000,000

189,000,000

174,000,000

8,000,000

12,000,000

1,078,000,000

968,000,000

5,378,000,000

5,132,000,000

534,000,000

550,000,000

5,000,000

8,000,000

477,000,000

514,000,000

24,000,000

29,000,000

1,048,000,000

1,101,000,000

7,504,000,000

7,201,000,000

Long-term debt of variable interest entities due within one year

400,000,000

110,000,000

65,000,000

63,000,000

190,000,000

210,000,000

125,000,000

148,000,000

44,000,000

41,000,000

56,000,000

59,000,000

Customer deposits

75,000,000

84,000,000

22,000,000

18,000,000

71,000,000

25,000,000

1,048,000,000

758,000,000

1,446,000,000

1,596,000,000

Long-term debt of variable interest entity

258,000,000

299,000,000

332,000,000

Deferred income taxes and unamortized investment tax credits

1,598,000,000

1,491,000,000

8,000,000

1,000,000

208,000,000

212,000,000

212,000,000

200,000,000

84,000,000

52,000,000

2,110,000,000

1,956,000,000

5,161,000,000

4,900,000,000

1,360,000,000

1,294,000,000

793,000,000

817,000,000

BGE preference stock not subject to mandatory redemption

2,153,000,000

2,111,000,000

190,000,000

Total equity

2,343,000,000

2,301,000,000

7,504,000,000

7,201,000,000

Baltimore Gas and Electric Company [Member] | Removal Costs [Member]

21,000,000

18,000,000

Baltimore Gas and Electric Company [Member] | Customer Rate Credit [Member]

212,000,000

$ 200,000,000

1,000,000

$ 0

[1]	Current and noncurrent assets are shown net of collateral of $92 million and $263 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(49) million and $(113) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $193 million at September 30, 2012.
[2]	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.

Consolidated Balance Sheets (Unaudited) (Parenthetical)	Sep. 30, 2012 USD ($)	Sep. 30, 2012 shares	Dec. 31, 2011 USD ($)	Dec. 31, 2011 shares
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral \| $	$ 314,000,000		$ 329,000,000
Unamortized Energy Contracts Assets [Abstract]
Unamortized energy contract assets related to CENG \| $	0		0
Shareholders' equity
Common stock, par value
Common stock, shares authorized		2,000,000,000		2,000,000,000
Common stock, shares outstanding		854,283,102		663,000,000
Treasury Stock, Shares held		35,000,000
PECO Energy Co [Member]
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral \| $	$ 314,000,000		$ 329,000,000

Consolidated Statement of Changes in Shareholders Equity (Unaudited) - 9 months ended Sep. 30, 2012 - USD ($)	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] 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] Common Stock [Member]	Baltimore Gas and Electric Company [Member] Nonredeemable Preferred Stock [Member]	Baltimore Gas and Electric Company [Member] Retained Earnings
Beginning Balance at Dec. 31, 2011								$ 8,708,000,000	$ 4,232,000,000	$ 3,556,000,000	$ 915,000,000	$ 5,000,000
Beginning Balance at Dec. 31, 2011	$ 14,388,000,000	$ 9,107,000,000	$ (2,327,000,000)	$ 10,055,000,000	$ (2,450,000,000)	$ 3,000,000																	$ 2,301,000,000
Beginning Balance at Dec. 31, 2011		698,112,000
Beginning Balance at Dec. 31, 2011	14,385,000,000												$ 2,938,000,000	$ 2,379,000,000	$ 559,000,000		$ 7,037,000,000	$ 1,588,000,000	$ (1,000,000)	$ 5,003,000,000	$ (1,639,000,000)	$ 2,086,000,000	2,111,000,000	$ 1,294,000,000	$ 190,000,000	$ 817,000,000
Net income	787,000,000			782,000,000		(6,000,000)	$ 11,000,000	419,000,000	425,000,000			(6,000,000)	300,000,000		300,000,000		219,000,000				219,000,000		(14,000,000)			(14,000,000)
Net income on common stock	782,000,000												297,000,000										(24,000,000)
Long-term incentive plan activity		2,790,000
Appropriation of retained earnings for future dividends																	0				(219,000,000)	219,000,000
Long-term incentive plan activity	122,000,000	$ 122,000,000	0	0
Common stock dividends	(878,000,000)			(878,000,000)									(258,000,000)		(258,000,000)		(95,000,000)					(95,000,000)
Common stock issuance - Constellation merger - Shares		188,124,000
Common stock issuance - Constellation merger - Value	7,365,000,000	$ 7,365,000,000
Contribution from parent	92,000,000					92,000,000	0	5,258,000,000		5,258,000,000		0											66,000,000
Distribution to members								(1,384,000,000)	(1,384,000,000)
Allocation of tax benefit from members								0		0
Allocation of tax benefit from parent																	13,000,000			13,000,000
BGE preference stock acquired	193,000,000						193,000,000
Preferred security dividends	(11,000,000)			0			(11,000,000)						(3,000,000)		(3,000,000)								(10,000,000)			(10,000,000)
Other comprehensive income (loss), net of tax	45,000,000				45,000,000			(163,000,000)			(163,000,000)		1,000,000			$ 1,000,000	1,000,000		1,000,000
Ending Balance at Sep. 30, 2012								$ 12,930,000,000	$ 3,273,000,000	$ 8,814,000,000	$ 752,000,000	$ 91,000,000
Ending Balance at Sep. 30, 2012	22,103,000,000	$ 16,594,000,000	$ (2,327,000,000)	$ 9,959,000,000	$ (2,405,000,000)	$ 89,000,000	$ 193,000,000																2,343,000,000
Ending Balance at Sep. 30, 2012		889,026,000
Ending Balance at Sep. 30, 2012	$ 21,821,000,000												$ 2,978,000,000	$ 2,379,000,000	$ 598,000,000	$ 1,000,000	$ 7,175,000,000	$ 1,588,000,000	$ 0	$ 5,016,000,000	$ (1,639,000,000)	$ 2,210,000,000	$ 2,153,000,000	$ 1,360,000,000	$ 190,000,000	$ 793,000,000

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical)	9 Months Ended
	Sep. 30, 2012 USD ($)
Accumulated Other Comprehensive (Loss) Income, Net
Other comprehensive income, income taxes	$ 87,000,000
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	$ 107,000,000

Tax effect of the change in accumulated other comprehensive income (loss), that is, the tax effect on items included in other comprehensive income (loss) during the period.

Reference 1: 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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

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

Reference 4: 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 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 FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6909487&loc=d3e39076-109324

Reference 7: 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=6920043&loc=d3e640-108580

Reference 8: 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.

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

Basis of Presenation (Exelon, Generation, Comed and PECO)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

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

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. 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 includes the former Constellation customer supply and generation businesses. BGE, formerly Constellation's regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 3 - Merger and Acquisitions for further information regarding the merger transaction.

The energy generation business includes:

Generation: The business consists of owned, contracted and investments in electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and 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.

For financial statement purposes, beginning on March 12, 2012, disclosures that solely relate to Constellation or BGE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.

BGE was acquired through a transaction under common control (RF HoldCo LLC) and 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 three and nine months ended September 30, 2012 and 2011 and the financial position as of September 30, 2012 and December 31, 2011. However, for Exelon's financial reporting, Exelon is reporting BGE activity from March 12, 2012 through September 30, 2012.

Each of Generation's, ComEd's, PECO's and BGE's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of September 30, 2012 and 2011 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants' respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2011 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in BGE's Consolidated Statements of Cash Flows, Exelon's, Generation'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. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2011 Form 10-K.

Variable Interest Entities (Exelon, Generation and BGE)

Consolidated Variable Interest Entities

The Registrants' consolidated VIEs consist of:

BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, and issue and service bonds secured by rate stabilization property;
a retail gas group formed to enter into a collateralized gas supply agreement with a third-party gas supplier;
a retail power supply company;
a group of solar project limited liability companies formed to build, own, and operate solar power facilities, the largest of which is a 230-MW solar project under development in northern Los Angeles County, California. As of September 30, 2012, this project consisted primarily of Current Assets of $69 million, Noncurrent Assets of approximately $516 million, Current Liabilities of $230 million, and Noncurrent Liabilities of $159 million. See Note 3 – Other Acquisitions and Note 9 – Debt and Credit Agreements for additional information; and
several wind projects designed to develop, construct and operate wind generation facilities.

See Note 1 and Note 4 of the 2011 Form 10-K for Constellation and BGE for further information regarding investments in VIEs.

For each of the consolidated VIEs:

The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE. In the case of BondCo, BGE is required to remit all payments it receives from all residential customers for non-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30, 2012, BGE remitted $27 million and $62 million, respectively, to BondCo. During the three and nine months ended September 30, 2011, BGE remitted $27 million and $65 million, respectively, to BondCo.
Except for providing capital funding to the solar entities for ongoing construction of the solar power facilities and a $75 million parental guarantee to the third-party gas supplier in support of the retail gas group, during the three and nine months ended September 30, 2012:

Exelon, Generation and BGE did not provide any additional financial support to the VIEs;
Exelon, Generation and BGE did not have any contractual commitments or obligations to provide financial support to the VIEs; and
the creditors of the VIEs did not have recourse to Exelon's, Generation's or BGE's general credit.

At September 30, 2012, Exelon's, Generation's and BGE's consolidated financial statements include the following balances for the consolidated VIEs that were acquired as part of the merger:

		September 30, 2012
		Exelon		Generation		BGE
Current assets		$	398	$	348	$	49
Noncurrent assets			471		432		-
	Total assets	$	869	$	780	$	49

Current liabilities		$	269	$	193	$	75
Noncurrent liabilities			573		235		299
	Total liabilities	$	842	$	428	$	374

Unconsolidated Variable Interest Entities

Exelon's and Generation's variable interests in unconsolidated VIEs generally include three categories: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. As of the balance sheet date, the carrying amount of assets and liabilities in Exelon's and Generation's Consolidated Balance Sheets that relate to their involvement with the majority of the energy contracts and fuel purchase contracts with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Exelon and Generation for the deliveries associated with the current billing cycles under the contracts. Further, Exelon and Generation have not provided or guaranteed the debt or equity support, or liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of the involvement with these VIEs.

As of September 30, 2012, Exelon and Generation did have exposure to loss associated with six VIEs for which they were not the primary beneficiary; including certain equity method investments and certain energy contracts. The following table presents summary information about the unconsolidated VIE entities for which Exelon and Generation have exposure to loss, which were added as a result of the merger:

				Equity
		Energy		Method
		Contract		Investment
September 30, 2012		VIEs		VIEs		Total
Total assets (a)		$	280	$	342	$	622
Total liabilities (a)			217		95		312
Registrants' ownership interest (a)			0		98		98
Other ownership interests (a)			63		149		212
Registrants' maximum exposure to loss:
	Letters of credit		8		0		8
	Carrying amount of equity method investments		0		78		78
	Debt and payment guarantees		0		5		5

_________________

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.

During the nine months ended September 30, 2012, ComEd, PECO, BGE and Generation assessed their contracts and determined that, other than the items discussed in this note there were no changes in their variable interests, primary beneficiary determinations or conclusions regarding consolidation of VIEs from December 31, 2011. See Note 1 of the Exelon 2011 Form 10-K and Note 1 and Note 4 of the 2011 10-K for BGE for further information regarding the Registrants' VIEs.

RF HoldCo LLC, a bankruptcy-remote special purpose subsidiary, holds all of Exelon's common equity interests in BGE. This subsidiary is not a VIE. However, due to Exelon's ownership of 100% of the voting interests of RF HoldCo LLC, Exelon consolidates this subsidiary as a voting interest entity.

BGE and RF HoldCo are separate legal entities and are not liable for the debts of Exelon. Accordingly, creditors of Exelon may not satisfy their debts from the assets of BGE and RF HoldCo LLC except as required by applicable law or regulation. Similarly, Exelon is not liable for the debts of BGE or RF HoldCo LLC. Accordingly, creditors of BGE and RF HoldCo LLC may not satisfy their debts from the assets of Exelon except as required by applicable law or regulation.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

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New Accounting Pronouncements And Changes In Accounting Principles Abstract

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

9 Months Ended

Sep. 30, 2012

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

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

The following recently issued accounting standard was adopted by the Registrants during the period.

Fair Value Measurement

In May 2011, the FASB issued authoritative guidance amending existing guidance for measuring and disclosing fair value. The new guidance does not impact the fair value measurements included in the Registrants' Consolidated Financial Statements as of September 30, 2012. The guidance is effective for the Registrants beginning with the period ended March 31, 2012 and is required to be applied prospectively. However, the Company updated the existing fair value disclosures during the first quarter of 2012 to comply with the requirements for this standard. See Note 7 – Fair Value of Financial Assets and Liabilities for the new disclosures.

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.

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Regulatory Matters (Exelon, Generation, ComEd and PECO)

Regulatory Matters (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2012

Regulatory Matters [Abstract]

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

Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)

Except for the matters noted below, the disclosures set forth in Note 2 of the Exelon 2011 Form 10-K and Note 6 of Constellation's and BGE's 2011 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd).

Background

EIMA provides a structure for substantial capital investment 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 and will provide greater certainty as to the recovery of those costs. 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 beginning in 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.

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. On May 29, 2012, the ICC issued its final 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 reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 periods 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 the issues of ComEd's pension asset recovery, the use of average or year-end rate base in determining ComEd's reconciliation revenue requirement and the interest rate charged on over/under recovered costs. On October 3, 2012, the ICC issued its final order (Rehearing Order) in ComEd's expedited rehearing. The Rehearing Order adopted 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. ComEd expects to record in the fourth quarter of 2012 an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order.

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 delay of installation of additional smart meters. ComEd has 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 planned capital investment to future years. An Order from the ICC on ComEd's revised deployment plan is due by December 5, 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 rates will take effect in January 2013). ComEd updated its 2011 reconciliation filing on June 12, 2012 to reflect the impacts of the May Order discussed above. 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 September 30, 2012 and December 31, 2011, ComEd recorded an estimated net regulatory asset of $74 million and $84 million, respectively, which represents the ICC's approved distribution formula and associated rulings as of September 30, 2012 and 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 for the twelve months ended December 31, 2011 and for the nine months ended September 30, 2012. The evidentiary hearing in ComEd's 2011 reconciliation rate case was held on September 25, 2012, and a final order is due by December 26, 2012.

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 ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order in the remand 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. 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 base 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, which would have an immaterial impact at ComEd and Exelon.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from its retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. 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. EIMA 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. See Note 16 – Commitments and Contingencies for additional information on ComEd's energy commitments.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO's PAPUC-approved DSP Program, under which PECO is providing default electric service, has a 29-month term that began January 1, 2011 and ends May 31, 2013. Under the DSP Program, 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. The filing and implementation costs of the DSP Program were recorded as a regulatory asset and are being recovered through the GSA over its 29-month term. In January and April 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, for electric supply for default electric service which included full requirements fixed price contracts for its residential, small commercial and medium commercial procurement classes that commenced in June 2012, hourly spot market price full requirements contracts for its small and medium commercial and large commercial and industrial procurement classes that commenced in June 2012 and block contracts for its residential class beginning in December 2012. In September 2012, PECO completed its last competitive procurement under the DSP Program for electric supply for default electric service. PECO entered into block contracts with PAPUC-approved bidders, including Generation, for its residential class beginning in December 2012. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations and Comprehensive Income.

On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Plan, which was filed with the PAPUC in January 2012. The plan, 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 second DSP Program, 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, administrative costs and AEPS costs and is subject to adjustments at least quarterly for any over or under collections. The filing and implementation costs of the DSP Program were recorded as a regulatory asset and are being recovered through the GSA over its 24-month term.

In the second DSP plan, the load for the residential and small and medium commercial classes will be served through competitively procured contracts for fixed price, full requirements contracts of two years or less. Similar to the current DSP plan, 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. The first competitive procurement is expected to take place for the residential class in December 2012 for default electric service commencing June 1, 2013.

In addition, the second DSP plan includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. In the PAPUC's Opinion and Order, PECO was also directed to develop a plan by January 1, 2014 that will allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs. PECO expects to file its plan by March 2013.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009 by the PAPUC, PECO began the first phase of its smart meter deployment in March 2012. The first phase calls for the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. The first phase of smart meter deployment was estimated to cost $415 million.

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in SGIG funds. Of the $200 million in grant money, $140 million is being applied to the AMI technology deployment, including 600,000 smart meters in the first phase deployment. Therefore, the SGIG funds are being used to offset the impact to ratepayers of the smart meter deployment required by Act 129. As of September 30, 2012, PECO has received $130 million in reimbursements from the DOE for its smart meter deployment and other grid improvements. PECO's outstanding receivable from the DOE for reimbursable costs was $16 million as of September 30, 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 its 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 will replace 186,000 previously installed meters with Landis+Gyr (L+G) meters by the end of November 2012 and will use L+G meters for the remainder of the first phase deployment.

As of September 30, 2012, the carrying value of the original meters, including installation and removal costs, owned by PECO was approximately $18 million, net of approximately $16 million of reimbursements from the DOE. PECO does not expect the change in vendor to impact its eligibility for the $200 million in SGIG funds. PECO is seeking and anticipates full recovery of these meter and other incremental costs incurred in response to the overheating incidents, and, therefore, expects this matter will not have a material impact on PECO's results of operations, cash flows or financial position.

Energy Efficiency Program (Exelon and PECO). PECO's PAPUC-approved EE&C Plan has a four-year term that began on June 1, 2009 and sets forth how PECO will meet the various reduction targets established by Act 129's EE&C provisions. In addition to energy consumption reductions, Act 129 requires Pennsylvania electric distribution companies to reduce peak demand by a minimum of 4.5% of their annual system peak demand in the 100 hours of highest demand. The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a filing with the PAPUC by December 2012.

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 EE&C programs, which will go into effect on June 1, 2013, but defers a decision on peak demand reduction requirements until the first quarter of 2013. The order tentatively establishes PECO's three year cumulative consumption reduction target at 2.9%. The order also provides the opportunity for any electric utility to challenge its proposed target in an evidentiary hearing, which PECO requested on August 20, 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 2, 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 that the total cost of the plan may not exceed 2% of the electric company's total annual revenue as of December 31, 2006.

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 a 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 September 30, 2012.

Investigation of PA 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 October 12, 2012, the PAPUC approved PECO's second DSP plan, 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. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to an expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for the development of their next default service plan. Further, the PAPUC issued a Secretarial Letter on September 27, 2012, outlining its proposed end-state for default service, which included short-term contracts for all default service providers of approximately 3 months and the inclusion of CAP customers in the customer choice programs. A Tentative Order on these proposals is expected to be issued in November 2012.

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' 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 in future test years. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11.

2010 Natural Gas Distribution Rate Case (Exelon and PECO). PECO's 2010 natural gas distribution rate case settlement approved by the PAPUC stipulates that the expected cash benefit resulting from the application of new tax repairs deduction methodologies for 2010 and prior tax years must 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. 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, for which PECO has recorded a regulatory liability that is reflected on Exelon's and PECO's Consolidated Balance Sheets as of September 30, 2012. This amount is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2013. 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 natural gas distribution base rate case. See Note 10 – Income Taxes for additional information.

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 which 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 which 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. 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 September 30, 2012, BGE had received $126 million in reimbursements from the DOE. As of September 30, 2012, BGE's outstanding receivable from the DOE for reimbursable costs was $13 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 a 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, with an assumed commercial operation date of June 1, 2015. The initial term of the proposed contract is 20 years. The CfD will provide that the utilities will pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from bidding the unit into the PJM markets. 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.

Federal Regulatory Matters

Annual Transmission Formula Rate Update (Exelon, ComEd and BGE). 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 for the prior year, primarily due to lower debt costs. As part of the FERC-approved settlement of ComEd's 2007 rate case, the 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%.

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.

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 RTEP baseline project commitments changed as of September 30, 2012 from December 31, 2011 as follows:

ComEd increased its RTEP baseline project commitments by $124 million for the nine months ended September 30, 2012, reflecting increases of $8 million, $57 million, $9 million, $20 million, $25 million and $5 million for 2012, 2013, 2014, 2015, 2016 and 2017, respectively.
PECO increased its RTEP baseline project commitments by $86 million for the nine months ended September 30, 2012, reflecting increases of $6 million, $9 million, $11 million, $13 million, $21 million and $26 million for 2012, 2013, 2014, 2015, 2016 and 2017, respectively.
BGE's increased its RTEP baseline project commitments by $165 million for the nine months ended September 30, 2012, reflecting (decreases)/increases of $(32) million, $(20) million, $44 million, $115 million, $52 million and $6 million for 2012, 2013, 2014, 2015, 2016, and 2017, respectively.

PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) intended to ensure that a competitive capacity offer is based on the costs and competitive market revenues of a new entry unit. On February 1, 2011, in response to the enactment of New Jersey Senate Bill 2381, Exelon Generation joined the PJM Power Providers Group (P3) complaint at FERC seeking a revision to PJM's MOPR to preclude the exercise of buyer market power. In response to P3's complaint, PJM filed revisions to the MOPR which were largely approved by FERC in its April 12, 2011 Order. The revised MOPR, among other things, sets a minimum price level for sell offers for capacity from certain types of new generation resources submitted in PJM's capacity market auctions. While a number of state regulators and consumer groups opposed the MOPR revision, the changes were in line with recent FERC orders regarding capacity markets in the New York and New England ISOs. A number of parties filed for rehearing of the FERC order. FERC generally denied rehearing, and the FERC orders 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 2015/2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. There is potential that states will expand such state-sanctioned subsidy programs or that other states may seek to establish similar programs. Exelon believes that further revisions to the MOPR may be necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM. In late September, PJM announced to all of its stakeholders that a group of its stakeholders had developed a proposal addressing the shortcomings of the current MOPR. PJM plans to have its stakeholders review and consider these proposed MOPR changes in October and November with a potential vote on these proposed MOPR changes in late November 2012. PJM would need to obtain approval from the FERC prior to implementing any changes. Exelon 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.

License Renewals (Exelon and Generation). On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project. The FERC review process is scheduled to be completed by August 31, 2014 and September 1, 2014, when the current Conowingo and Muddy Run licenses expire.

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 September 30, 2012 and December 31, 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. For additional information on the specific regulatory assets and liabilities, refer to Note 2 of the Exelon 2011 Form 10-K for Exelon, ComEd and PECO and Note 6 of BGE's 2011 Form 10-K.

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits(a)	$	264	$	3,499	$	0	$	0	$	2		$	0	$	1	$	0
Deferred income taxes			13		1,346		5		62		0			1,220		8		64
AMI and smart meter programs			2		54		2		5		0			24		0		25
Under-recovered distribution service
	costs		0		119		0		119		0			0		0		0
Debt costs			14		71		11		65		3			6		2		9
Fair value of BGE long-term debt (b)			43		226		0		0		0			0		0		0
Fair value of BGE supply contract (c)			94		31		0		0		0			0		0		0
Severance			30		36		25		19		0			0		5		17
Asset retirement obligations			0		84		0		59		0			25		0		0
MGP remediation costs			65		227		58		190		6			35		1		2
RTO start-up costs			3		3		3		3		0			0		0		0
Under-recovered electric universal
	service fund costs		8		0		0		0		8			0		0		0
Financial swap with Generation			0		0		352		0		0			0		0		0
Renewable energy and associated
	RECs		17		53		17		53		0			0		0		0
Under-recovered energy and
	transmission costs		62		0		22		0		7	(d)		0		33		0
DSP Program costs			2		2		0		0		2			2		0		0
DSP II Program costs			0		2		0		0		0			2		0		0
Deferred storm costs			3		7		0		0		0			0		3		7
Electric generation-related
	regulatory asset		16		44		0		0		0			0		16		44
Rate stabilization deferral			65		244		0		0		0			0		65		244
Energy efficiency and demand
	response programs		55		117		0		0		0			0		55		117
Other			30		27		16		14		14			9		0		5

Total regulatory assets		$	786		6,192	$	511	$	589	$	42		$	1,323	$	189	$	534

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,383	$	0	$	2,021	$	0		$	362	$	0	$	0
Removal costs			94		1,397		73		1,185		0			0		21		212
Energy efficiency and demand
	response programs		82		33		37		0		45			33		0		0
Electric distribution tax repairs			18		138		0		0		18			138		0		0
Gas distribution tax repairs			5		49						5			49
Over-recovered distribution service
	costs		45		0		45		0		0			0		0		0
Over-recovered uncollectible
	accounts		10		0		10		0		0			0		0		0
Over-recovered energy and
	transmission costs		39		0		7		0		32	(e)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			1		0		0		0		1			0		0		0
Customer rate credit			1		0		0		0		0			0		1		0
Other			1		0		0		0		1			0		0		0

Total regulatory liabilities		$	299	$	4,000	$	172	$	3,206	$	105		$	582	$	22	$	212

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		7		64
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	(d)		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		3

Total regulatory assets		$	390	$	4,518	$	657	$	699	$	39		$	1,216	$	174	$	550

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	(e)		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

Total regulatory liabilities		$	197	$	3,627	$	137	$	3,042	$	60		$	585	$	18	$	200

As of September 30, 2012, pension and other postretirement benefit regulatory assets include a regulatory asset established at the date of the merger related to the recognition of BGE's share of the underfunded status of the defined benefit postretirement plan as a liability on Exelon's Consolidated Balance Sheets. The regulatory asset is being amortized in accordance with the authoritative guidance for pensions and postretirement benefits over a period of approximately 12 years. BGE is currently recovering these costs through base rates. BGE is not earning a return on the recovery of these costs in base rates.
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.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates.
Includes $5 million related to under-recovered electric transmission costs and $2 million related to under-recovered natural gas costs under the PGC as of September 30, 2012. The balance as of December 31, 2011 related to under-recovered electric transmission costs.
Relates to the over-recovered electric supply costs under the GSA as of September 30, 2012. Includes $5 million related to the over-recovered natural gas costs under the PGC and $25 million related to the over-recovered electric supply costs under the GSA as of December 31, 2011.

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. Purchased receivables are classified in other accounts receivable, net on Exelon's, ComEd's, PECO's and BGE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of September 30, 2012 and December 31, 2011.

As of September 30, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	203	$	56	$	72	$	75
Allowance for uncollectible accounts (b)		(18)		(6)		(7)		(5)
Purchased receivables, net	$	185	$	50	$	65	$	70

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 and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

Merger and Acquisitions (Exelon and Generation)

9 Months Ended

Sep. 30, 2012

Acquisitions [Line Items]

Acquisitions (Exelon and Generation)

3. 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 the customer supply and generation businesses 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 14 - Stock-Based Compensation Plans 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 nine months ended September 30, 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 estimate of $1 billion of direct investment 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 2 to 3 years. The $1 billion estimate also includes $625 million for Exelon and Generation's commitment to develop 285 – 300 MW 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 September 30, 2012, amounts reflected in the Exelon and Generation consolidated financial statements for these expenditure commitments were immaterial.

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 will be required 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. In October 2011, Exelon and Constellation reached a settlement with the PJM Independent Market Monitor, who had previously raised market power concerns regarding the merger. The settlement contains a number of commitments by Exelon, including limiting the universe of potential buyers of the divested assets to entities without significant market shares in the relevant PJM markets. The settlement also includes assurances about how Generation will bid its units into the PJM markets. The proposed divestiture and the settlement with the PJM Market Monitor were filed with FERC and the MDPSC and were included in their final orders approving the merger.

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, a subsidiary of Riverstone Holdings LLC. The DOJ approved the buyer on October 18, 2012 and the final FERC approval was obtained on October 19, 2012; the transaction is expected to close in the fourth quarter 2012. The agreement includes a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in estimated net proceeds from the sale of approximately $356 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 and carrying value. The final loss amount will be updated for adjustments related to fuel inventory, capital expenditures, and timing of the closing.

As of September 30, 2012, these assets, classified as held for sale, are valued at estimated fair value less costs to sell of $339 million, after reflecting the $278 million impairment, and are included in the other current assets balance on Exelon's and Generation's Consolidated Balance Sheets.

Subsequent to the merger, Generation discovered that, for the first two weeks following merger close, 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. Generation is in discussions with the DOJ regarding resolution of this matter. The final resolution is not expected to 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 – Basis of Presentation for additional information on BGE's push-down accounting treatment. Also see Note 4 – Regulatory Matters for additional information on BGE's regulatory assets.

The preliminary 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 and third 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 contracts 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 acquisition 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 September 30, 2012 was as follows:

Preliminary Purchase Price Allocation, excluding amortization	Exelon		Generation
Current assets	$	4,936	$	3,638
Property, plant and equipment		9,240		3,948
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		2,668		1,266
Total assets		23,201		14,469

Current liabilities		3,431		2,798
Unamortized energy contracts		1,722		1,512
Long-term debt, including current maturities		6,038		2,972
Noncontrolling interest		92		92
Deferred credits and other liabilities and preferred securities		4,553		1,837
Total liabilities, preferred securities and noncontrolling interest		15,836		9,211
Total purchase price	$	7,365	$	5,258

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 amortization expense for the three months ended September 30, 2012 and for the period March 12, 2012 to September 30, 2012 were $224 million and $714 million, respectively. 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. The intangible assets are amortized on a straight line basis over an estimated 10 year useful life as amortization expense. 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 on a straight line basis over the useful life of the underlying assets averaging approximately 12.4 years as amortization expense. 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 September 30, 2012:

								Estimated amortization expense
Description	Weighted Average Amortization	Gross		Accumulated Amortization		Net		Remainder of 2012		2013		2014		2015		2016
Unamortized energy contracts, net (a)	1.5	$	1,496	$	(714)	$	782	$	267	$	396	$	76	$	18	$	(31)
Trade name	10.0		243		(14)		229		10		24		24		24		24
Retail relationships	12.4		214		(9)		205		8		19		19		19		19

Total, net		$	1,953	$	(737)	$	1,216	$	285	$	439	$	119	$	61	$	12

(a) Includes the fair value of BGE's power and gas supply contracts for which an offsetting 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 $720 million and net income of $0 million during three months ended September 30, 2012, and operating revenues of $ 1,388 million and net loss of $49 million during the nine months ended September 30, 2012.

During the three months ended September 30, 2012, Exelon, Generation, PECO and BGE incurred merger and integration-related costs of $87 million, $79 million, $3 million and $1 million, respectively. During the nine months ended September 30, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $671 million, $283 million, $2 million, $13 million and $155 million, respectively. These amounts do not include merger and integration-related costs of $34 million and $22 million incurred at ComEd and BGE, respectively, that 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 nine months ended September 30, 2012.

During the three months ended September 30, 2011, Exelon, Generation, ComEd and PECO incurred merger and integration-related costs of $18 million, $5 million, $2 million and $1 million, respectively. During the nine months ended September 30, 2011, Exelon, Generation, ComEd and PECO incurred merger and integration-related costs of $43 million, $6 million, $2 million and $1 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 September 30, 2012, for Exelon is $130 million, which includes $76 million, $18 million, $8 million and $19 million for Generation, ComEd, PECO and BGE, respectively. Estimated costs to be incurred after September 30, 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 12 – Retirement Benefits for additional information on the contractual termination benefits.

For the three and nine months ended September 30, 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:

Three Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd		PECO		BGE
Severance charges	$	8	$	4	$	1	$	1	$	1
Stock compensation		3		2		1		0		0
Total severance benefits	$	11	$	6	$	2	$	1	$	1

Nine Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	117	$	68	$	16	$	8	$	18
Stock compensation		6		4		1		0		0
Other charges		7		4		1		0		1
Total severance benefits	$	130	$	76	$	18	$	8	$	19

_________________

The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively.
ComEd established regulatory assets of $18 million, as of September 30, 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 September 30, 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:

Three Months Ended September 30, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at June 30, 2012	$	118	$	30	$	2	$	0	$	12
Severance charges (a)		7		4		0		0		0
Stock compensation		3		1		0		0		0
One-time termination benefits (b)		1		1		0		0		0
Other charges (c)		0		0		0		0		0
Payments		(9)		(2)		0		0		(1)
Balance at September 30, 2012	$	120	$	34	$	2	$	0	$	11

Nine Months Ended September 30, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2011	$	0	$	0	$	0	$	0	$	0
Severance charges (a)		114		31		2		0		11
Stock compensation		6		2		0		0		0
One-time termination benefits (b)		3		1		0		0		0
Other charges (c)		7		2		0		0		1
Payments		(10)		(2)		0		0		(1)
Balance at September 30, 2012	$	120	$	34	$	2	$	0	$	11

Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits.
One-time termination benefits began to be recognized 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 and will continue through 2016. 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 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
		Three Months Ended September 30,				Three Months Ended September 30,
		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	4,293	$	5,133	$	6,841	$	8,219
Net income attributable to Exelon		282		163		492		379

Basic Earnings Per Share		n.a.		n.a.	$	0.58	$	0.45
Diluted Earnings Per Share		n.a.		n.a.		0.57		0.44

	Generation				Exelon
		Nine Months Ended September 30,				Nine Months Ended September 30,
		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	12,753	$	14,996	$	20,084	$	23,839
Net income attributable to Exelon		805		690		1,439		1,119

Basic Earnings Per Share		n.a.		n.a.	$	1.79	$	1.32
Diluted Earnings Per Share		n.a.		n.a.		1.79		1.31

_________________

The amounts above include non-recurring costs directly related to the merger of $69 million and $318 million for the three and nine months ended September 30, 2011, respectively.
The amounts above include non-recurring costs directly related to the merger of $74 million and $242 million for the three and nine months ended September 30, 2011, respectively.

Other Acquisitions (Exelon and Generation)

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired all of the interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, Inc., which developed and will build, operate and maintain 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 9 - Debt and Credit Agreements for additional information.

Other Development. As part of its plan to construct multiple wind facilities in 2012, Generation has acquired several project entities. In addition, Generation has acquired solar projects and interests in oil and gas production facilities in 2012. The acquisitions are not considered material individually or in the aggregate for disclosure.

^[1]

Acquisitions (Exelon and Generation)

Acquisitions [Line Items]

Other Acquisitions (Exelon and Generation)

[1]	The amounts above include non-recurring costs directly related to the merger of $69 million and $318 million for the three and nine months ended September 30, 2011, respectively.

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

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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Section 50
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4934-128472

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
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Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1383-128463

Equity Method Investments and Joint Ventures [Line Items]

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

9 Months Ended

Sep. 30, 2012

Investment in Constellation Energy Nuclear Group, LLC (CENG)

5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation's total equity in earnings (losses) on the investment in CENG is as follows:

	Three Months			For the Period March 12,
	Ended September 30,			through September 30,
	2012		2012
Equity investment income	$	58	$	53
Amortization of basis difference in CENG		(57)		(131)
Total equity in earnings (losses) - CENG	$	1	$	(78)

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 and Generation)

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. The SSA includes both a consumption-based pricing structure and a fixed-price structure which are subject to change in future years based on the level of service needed. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA is in the process of being amended so that the charges 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)		Income/(Expense)			Accounts
	Three Months		For the Period		Income	Receivable/
	Ended		March 12 through		Statement	(Accounts Payable)
Agreement	September 30, 2012		September 30, 2012		Classification	At September 30, 2012
PPA	$	(282)	$	(541)	Purchased power and fuel	$	(86)
PSAA		1		2	Operating revenues		-
SSA		14		30	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% to Generation and 50% to EDF. As of September 30, 2012, CENG had borrowed $43 million from Generation. The unsecured promissory note matured on October 31, 2012, and all amounts due were paid in full as of that date.

Equity Method Investments and Joint Ventures [Line Items]

Investment in Constellation Energy Nuclear Group, LLC (CENG)

5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

	Three Months			For the Period March 12,
	Ended September 30,			through September 30,
	2012		2012
Equity investment income	$	58	$	53
Amortization of basis difference in CENG		(57)		(131)
Total equity in earnings (losses) - CENG	$	1	$	(78)


	Income/(Expense)		Income/(Expense)			Accounts
	Three Months		For the Period		Income	Receivable/
	Ended		March 12 through		Statement	(Accounts Payable)
Agreement	September 30, 2012		September 30, 2012		Classification	At September 30, 2012
PPA	$	(282)	$	(541)	Purchased power and fuel	$	(86)
PSAA		1		2	Operating revenues		-
SSA		14		30	Operating revenues		5

The entire disclosure for equity investment, or group of investments, for which combined disclosure is appropriate, including: (a) the name of each investee and percentage of ownership of common stock, (b) accounting policies for investments in common stock, (c) difference between the amount at which the investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference, (d) the total fair value of each identified investment for which a market value is available, (e) summarized information as to assets, liabilities, and results of operations of the investees (for investments in unconsolidated subsidiaries, common stock of joint ventures, or other investments using the equity method), and (f) material effects of possible conversions, exercises, or contingent issuances of the investee. Other disclosures include (a) the names of any investee in which the investor owns 20 percent or more of the voting stock and investment is not accounted for using the equity method, and the reasons why not, and (b) the names of any investee in which the investor owns less than 20 percent of the voting stock and the investment is accounted for using the equity method, and the reasons why it is.

Intangible Assets (Exelon, Generation, ComEd and PECO)

Intangible Assets (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2012

Intangible Assets [Abstract]

6. Goodwill (Exelon and ComEd)

Goodwill

Under the authoritative guidance for the accounting for goodwill, ComEd is required to perform an assessment for possible impairment of its goodwill at least annually or more frequently if an event occurs, 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 May 2012, the ICC issued a final Order (Order) in ComEd's 2011 formula rate proceeding under the EIMA that reduced ComEd's annual revenue requirement being recovered in current rates by $168 million. Management concluded that the Order represents 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 the annual impairment test, 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 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 are estimated to reduce ComEd's revenue requirement recovered in rates by approximately $75 - $130 million annually. The assessment also reflects 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 requirement. See Note 4 – Regulatory Matters for further detail.

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.

Fair Value of Financial Assets and Liabilities [Abstract]

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

9 Months Ended

Sep. 30, 2012

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

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

Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants' short-term liabilities, long-term debt, SNF obligation and preferred securities as of September 30, 2012 and December 31, 2011:

Exelon

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	289	$	4	$	285	$	0	$	737	$	737
Long-term debt (including amounts
	due within one year)		18,715		0		20,762		38		12,627		14,488
Long-term debt to financing trusts			649		0		650		0		390		358
SNF obligation			1,020		0		780		0		1,019		886
Preferred securities of subsidiary			87		0		83		0		87		79

Generation

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	11	$	0	$	11	$	0	$	2	$	2
Long-term debt (including amounts
	due within one year)		7,383		0		7,839		20		3,677		4,231
SNF obligation			1,020		0		780		0		1,019		886

ComEd

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	35	$	0	$	35	$	0	$	0	$	0
Long-term debt (including amounts
	due within one year)		5,217		0		6,297		18		5,665		6,540
Long-term debt to financing trust			206		0		208		0		206		184

PECO

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	225	$	0	$	225	$	0	$	225	$	225
Long-term debt (including amounts
	due within one year)		2,322		0		2,682		0		1,972		2,295
Long-term debt to financing trusts			184		0		180		0		184		174
Preferred securities			87		0		83		0		87		79

BGE

		September 30, 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)		2,210		0	2,547	0		2,101		2,377
Long-term debt to financing trusts			258		0	264	0		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 9 - 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 are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants' debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

The Registrants also have tax-exempt debt. 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 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 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.

Preferred Securities of Subsidiary, Long-Term Debt to Financing Trusts and Junior Subordinated Debentures. The fair value of these securities is determined using observable market prices on the last trade date of the quarter as these securities are actively traded, 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 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 and investments priced using an alternative pricing mechanism.

There were no transfers between Level 1 and Level 2 during the nine months ended September 30, 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 September 30, 2012 and December 31, 2011:

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	1,117	$	0	$	0	$	1,117
Nuclear decommissioning trust fund investments
Cash equivalents		319		0		0		319
Equity
Equity securities		1,452		0		0		1,452
Commingled funds		0		1,906		0		1,906
Equity funds subtotal		1,452		1,906		0		3,358
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,100		0		0		1,100
Debt securities issued by states of the United States
and political subdivisions of the states		0		355		0		355
Debt securities issued by foreign governments		0		84		0		84
Corporate debt securities		0		1,734		0		1,734
Federal agency mortgage-backed securities		0		31		0		31
Commercial mortgage-backed securities (non-agency)		0		47		0		47
Residential mortgage-backed securities (non-agency)		0		15		0		15
Mutual funds		0		9		0		9
Fixed income subtotal		1,100		2,275		0		3,375
Direct lending securities		0		0		70		70
Other debt obligations		0		16		0		16
Nuclear decommissioning trust fund investments subtotal(b)		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		21		0		0		21
Commingled funds		0		20		0		20
Equity funds subtotal		21		20		0		41
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		78		15		0		93
Debt securities issued by states of the United States
and political subdivisions of the states		0		58		0		58
Corporate debt securities		0		260		0		260
Federal agency mortgage-backed securities		0		60		0		60
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Commingled funds		0		43		0		43
Fixed income subtotal		78		442		0		520
Direct lending securities		0		0		64		64
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal(c)		99		463		64		626

Rabbi trust investments
Cash equivalents		2		0		0		2
Mutual funds(d)(e)		69		0		0		69
Rabbi trust investments subtotal		71		0		0		71

Commodity mark-to-market derivative assets
Economic hedges		994		3,872		666		5,532
Proprietary trading		1,631		3,070		140		4,841
Effect of netting and allocation of collateral(f)		(2,597)		(5,695)		(238)		(8,530)
Commodity mark-to-market assets subtotal(g)		28		1,247		568		1,843
Interest rate mark-to-market derivative assets		0		125		0		125
Other investments		2		0		17		19

Total assets		4,188		6,032		719		10,939

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,225)		(2,814)		(351)		(4,390)
Proprietary trading		(1,678)		(2,881)		(222)		(4,781)
Effect of netting and allocation of collateral(f)		2,772		5,336		229		8,337
Commodity mark-to-market liabilities subtotal(g)(h)		(131)		(359)		(344)		(834)
Interest rate mark-to-market derivative liabilities		0		(95)		0		(95)
Deferred compensation		0		(101)		0		(101)

Total liabilities		(131)		(555)		(344)		(1,030)

Total net assets	$	4,057	$	5,477	$	375	$	9,909

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
Direct lending securities		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
Direct lending securities		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
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 $2 million and $(57) million at September 30, 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 $5 million and $9 million at September 30, 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 $54 million related to deferred compensation and $15 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 September 30, 2012 and December 31, 2011, respectively.

(f) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $175 million, $(359) million and $(9) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 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 $352 million and $0 million at September 30, 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 $17 million and $53 million at September 30, 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 table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2012 and 2011:

Three Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of June 30, 2012		$	54	$	59	$	295		$	17	$	425
Total realized / unrealized gains (losses)
	Included in net income		0		0		(97)	(a)		0		(97)
	Included in regulatory assets		2		0		41	(b)		0		43
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Change in collateral			0		-		(15)			0		(15)
Purchases, sales, issuances and settlements
	Purchases (c)		14		4		-			0		18

Balance as of September 30, 2012		$	70	$	64	$	224		$	17	$	375
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2012	$	0	$	0	$	(42)		$	0	$	(42)

Nine Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2011		$	13	$	37	$	17		$	0	$	67
Total realized / unrealized gains (losses)
	Included in net income		0		0		(157)	(a)		0		(157)
	Included in other comprehensive income		0		0		1			0		1
	Included in regulatory assets		2		0		36	(b)		0		38
Change in collateral			0		0		(7)			0		(7)
Purchases, sales, issuances and settlements
	Purchases (c)		55		36		329			17		437
	Sales		0		(9)		0			0		(9)
Transfers into Level 3			0		0		(34)			0		(34)
Transfers out of Level 3			0		0		39			0		39

Balance as of September 30, 2012		$	70	$	64	$	224		$	17	$	375
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012	$	0	$	0	$	(16)		$	0	$	(16)

(a) Includes the reclassification of $55 million and $141 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012.

(b) Excludes $35 million of decreases in fair value and $86 million of increases in fair value and $119 million and $427 million of realized losses due to settlements for the three and nine months ended September 30, 2012 of Generation's financial swap contract with ComEd, which eliminates 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.

Three Months Ended September 30, 2011			Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of June 30, 2011			$	0	$	34	$	(16)		$	18
Total realized / unrealized gains (losses)
	Included in income			0		0		(8)	(a)		(8)
	Included in other comprehensive income			0		0		(15)	(b)		(15)
	Included in regulatory assets			0		0		(18)			(18)
	Included in payable for Zion Station decommissioning			0		(3)		0			(3)
Change in collateral				0		0		8			8
Purchases, sales, issuances and settlements
	Purchases			6		17		0			23
	Sales			0		(10)		0			(10)
Transfers out of Level 3				0		0		24			24
Balance as of September 30, 2011			$	6	$	38	$	(25)		$	19
The amount of total gains included in income attributed to
	the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2011		$	0	$	0	$	(5)		$	-5

Nine Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Total
Balance as of December 31, 2010			$	0	$	0	$	50		$	50
Total realized / unrealized gains (losses)
	Included in other comprehensive income			0		0		(27)	(a)		(27)
	Included in regulatory assets			0		0		(51)	(b)		(51)
Change in collateral				0		0		15			15
Purchases, sales, issuances and settlements
	Purchases			6		60		4			70
	Sales			0		(22)		0			(22)
Transfers out of Level 3				0		0		(16)			(16)
Balance as of September 30, 2011			$	6	$	38	$	(25)		$	19
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2011		$	0	$	0	$	18		$	18

(a) Includes the reclassification of $4 million and $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2011, respectively.

(b) Excludes $7 million and $4 million of decreases in fair value and $88 million and $309 million of realized losses due to settlements associated with Generation's financial swap contract with ComEd and $3 million of changes in the fair value of Generation's block contracts with PECO for the nine months ended September 30, 2011. All items eliminate upon consolidation if Exelon's Consolidated Financial Statements.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2012 and 2011:


		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended
	September 30, 2012	$	(106)	$	9
Total gains (losses) included in income for the nine months ended
	September 30, 2012	$	(195)	$	38
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended September 30, 2012	$	(48)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the nine months ended September 30, 2012	$	(45)	$	29

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended
	September 30, 2011	$	(5)	$	(3)
Total gains (losses) included in income for the nine months ended
	September 30, 2011	$	2	$	(2)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the three months ended September 30, 2011	$	1	$	(6)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the nine months ended September 30, 2011	$	22	$	(4)

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 September 30, 2012 and December 31, 2011:

As of September 30, 2012	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents	$	518	$	0	$	0	$	518
Nuclear decommissioning trust fund investments
Cash equivalents		319		0		0		319
Equity
Equity securities		1,452		0		0		1,452
Commingled funds		0		1,906		0		1,906
Equity funds subtotal		1,452		1,906		0		3,358
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,100		0		0		1,100
Debt securities issued by states of the United States and
political subdivisions of the states		0		355		0		355
Debt securities issued by foreign governments		0		84		0		84
Corporate debt securities		0		1,734		0		1,734
Federal agency mortgage-backed securities		0		31		0		31
Commercial mortgage-backed securities (non-agency)		0		47		0		47
Residential mortgage-backed securities (non-agency)		0		15		0		15
Mutual funds		0		9		0		9
Fixed income subtotal		1,100		2,275		0		3,375
Direct lending securities		0		0		70		70
Other debt obligations		0		16		0		16
Nuclear decommissioning trust fund investments subtotal(b)		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		21		0		0		21
Commingled funds		0		20		0		20
Equity funds subtotal		21		20		0		41
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		78		15		0		93
Debt securities issued by states of the United States and
political subdivisions of the states		0		58		0		58
Corporate debt securities		0		260		0		260
Federal agency mortgage-backed securities		0		60		0		60
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Commingled funds		0		43		0		43
Fixed income subtotal		78		442		0		520
Direct lending securities		0		0		64		64
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal(c)		99		463		64		626

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		994		3,872		1,018		5,884
Proprietary trading		1,631		3,070		140		4,841
Effect of netting and allocation of collateral(f)		(2,597)		(5,695)		(238)		(8,530)
Commodity mark-to-market assets subtotal(g)		28		1,247		920		2,195
Interest Rate mark-to-market derivative assets		0		111		0		111
Other investments		2		0		17		19

Total assets		3,532		6,018		1,071		10,621

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,225)		(2,814)		(281)		(4,320)
Proprietary trading		(1,678)		(2,881)		(222)		(4,781)
Effect of netting and allocation of collateral(f)		2,772		5,336		229		8,337
Commodity mark-to-market liabilities subtotal		(131)		(359)		(274)		(764)
Interest rate mark-to-market derivative liabilities		0		(95)		0		(95)
Deferred compensation		0		(27)		0		(27)

Total liabilities		(131)		(481)		(274)		(886)

Total net assets	$	3,401	$	5,537	$	797	$	9,735

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
Direct lending securities		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
Direct lending securities		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 $5 million and $9 million at September 30, 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 September 30, 2012 and December 31, 2011, respectively.

(g) The Level 3 balance includes current and noncurrent assets for Generation of $352 million and $0 million at September 30, 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 three and nine months ended September 30, 2012 and 2011:

Three Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives				Other Investments	Total
Balance as of June 30, 2012		$	54	$	59	$	912			17	$	1,042
Total unrealized / realized gains (losses)
	Included in income		-		-		(112)	(a)		-		(112)
	Included in other comprehensive income		-		-		(139)	(b)		-		(139)
	Included in noncurrent payables to affiliates		2		-		-			-		2
	Included in payable for Zion Station decommissioning		-		1		-			-		1
Change in collateral			-		-		(15)			-		(15)
Purchases, sales, issuances and settlements
	Purchases (c)		14		4		-			-		18

Balance as of September 30, 2012		$	70	$	64	$	646		$	17	$	797
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2012	$	-	$	-	$	(77)		$	-	$	(77)

Nine Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives				Other Investments	Total
Balance as of December 31, 2011		$	13	$	37	$	817			-	$	867
Total unrealized / realized gains (losses)
	Included in income		-		-		(187)	(a)		-		(187)
	Included in other comprehensive income		-		-		(311)	(b)		-		(311)
	Included in noncurrent payables to affiliates		2		-		-			-		2
Change in collateral			-		-		(7)			-		(7)
Purchases, sales, issuances and settlements
	Purchases (c)		55		36		329			17		437
	Sales		-		(9)		-			-		(9)
Transfers into Level 3			-		-		(34)					(34)
Transfers out of Level 3			-		-		39			-		39

Balance as of September 30, 2012		$	70	$	64	$	646		$	17	$	797
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012	$	-	$	-	$	(77)		$	-	$	(77)

(a) Includes the reclassification of $35 million and $110 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012, respectively.

(b) Includes $35 million of decreases in fair value and $86 million of increases in fair value and realized losses due to settlements of $119 million and $427 million associated with Generation's financial swap contract with ComEd for the three and nine months ended September 30, 2012, respectively. 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.

Three Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of June 30, 2011		$	0	$	34	$	776		$	810
Total realized / unrealized gains (losses)
	Included in income		0		0		(8)	(a)		(8)
	Included in other comprehensive income		0		0		(110)	(b)		(110)
	Included in payable for Zion Station decommissioning		0		(3)		0			(3)
Changes in collateral			0		0		8			8
Purchases, sales, issuances and settlements
	Purchases		6		17		0			23
	Sales		0		(10)		0			(10)
Transfers out of Level 3 - Asset			0		0		24			24

Balance as of September 30, 2011		$	6	$	38	$	690		$	734

The amount of total gains included in income attributed to
	the change in unrealized (losses) related to assets and liabilities held for the three months ended September 30, 2011	$	0	$	0	$	(5)		$	(5)

Nine Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of December 31, 2010		$	0	$	0	$	1,030		$	1,030
Total realized / unrealized gains (losses)
	Included in other comprehensive income		0		0		(343)	(b)		(343)
Changes in collateral			0		0		15			15
	Purchases		6		60		4			70
	Sales		0		(22)		0			(22)
Transfers out of Level 3 - Liability			0		0		(16)			(16)

Balance as of September 30, 2011		$	6	$	38	$	690		$	734

The amount of total gains included in income attributed to
	the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2011	$	0	$	0	$	18		$	18

(b) Includes $7 million and $4 million of decreases in fair value realized losses reclassified from OCI due to settlements of $88 million and $309 million associated with Generation's financial swap contract with ComEd for the three and nine months ended September 30, 2011, and $3 million of decreases in fair value due to settlement of Generation's block contracts with PECO for the three and nine months ended September 30, 2011. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended September 30, 2012		$	(121)	$	9
Total gains (losses) included in income for the nine months ended
	September 30, 2012	$	(225)	$	38
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the three months ended September 30, 2012	$	(83)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the nine months ended September 30, 2012	$	(95)	$	18

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended
	September 30, 2011	$	(5)	$	(3)
Total gains (losses) included in income for the nine months ended September 30, 2011		$	2	$	(2)
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended September 30, 2011	$	1	$	(6)
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the nine months ended September 30, 2011	$	22	$	(4)

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 September 30, 2012 and December 31, 2011:

As of September 30, 2012		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds			9		0		0		9
	Rabbi trust investment subtotal		9		0		0		9

Total assets			9		0		0		9

Liabilities
Deferred compensation obligation			0		(9)		0		(9)
Mark-to-market derivative liabilities (b)(c)			0		0		(422)		(422)

Total liabilities			0		(9)		(422)		(431)

Total net assets (liabilities)		$	9	$	(9)	$	(422)	$	(422)

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 $352 million and $0 million at September 30, 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 $17 million and $53 million at September 30, 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 three and nine months ended and September 30, 2012:

Three Months Ended September 30, 2012	Mark-to-Market Derivatives
Balance as of June 30, 2012	$	(617)
Total realized / unrealized gains included in regulatory assets (a)(b)		195
Balance as of September 30, 2012	$	(422)

Nine Months Ended September 30, 2012	Mark-to-Market Derivatives
Balance as of December 31, 2011	$	(800)
Total realized / unrealized gains included in regulatory assets (a)(b)		378
Balance as of September 30, 2012	$	(422)

(a) Includes $35 million of increases in fair value and $86 million of decreases in fair value and realized gains due to settlements of $119 million and $427 million associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2012, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

(b) Includes $40 million and $33 million of increases in the fair value and realized losses due to settlements of $1 million and $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2012, respectively.

Three Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of June 30, 2011	$	(788)
Total realized / unrealized gains included in regulatory assets (a)(b)		76
Balance as of September 30, 2011	$	(712)

Nine Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(971)
Total realized / unrealized gains included in regulatory assets (a)(b)		259
Balance as of September 30, 2011	$	(712)

Includes $7 million and $4 million of increases in fair value and $88 million and $309 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2011, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $19 million and $54 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2011, respectively.

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 September 30, 2012 and December 31, 2011:

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	528	$	0	$	0	$	528
Rabbi trust investments - mutual funds(b)(c)		9		0		0		9

Total assets		537		0		0		537

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

Total liabilities		0		(18)		0		(18)

Total net assets (liabilities)	$	537	$	(18)	$	0	$	519

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 $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2012 and December 31, 2011, respectively.

PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 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 three and nine months ended September 30, 2011:

Three Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of June 30, 2011	$	(4)
Total realized gains included in regulatory assets		1
Balance as of September 30, 2011	$	(3)

Nine Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(9)
Total realized gains included in regulatory assets		6	(a)
Balance as of September 30, 2011	$	(3)

(a) Includes an increase of $3 million related to the settlement of PECO's block contract with Generation for the nine months ended September 30, 2011, which eliminate upon consolidation in Exelon's Consolidated Financial Statements.

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 September 30, 2012 and December 31, 2011:

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	52	$	0	$	0	$	52
Rabbi trust investments - mutual funds		5		0		0		5

Total assets		57		0		0		57

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

Total liabilities		0		(5)		0		(5)

Total net assets (liabilities)	$	57	$	(5)	$	0	$	52

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

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. See Note 11 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Direct lending funds are investments in managed funds which invest in private companies for long-term capital appreciation. The fair value of these securities is determined using either an enterprise value model or a bond valuation model. Investments in direct lending funds 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.

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 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 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 8 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). The Registrants' deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants' deferred compensation obligations is based on the market value of the participants' notional investment accounts. The 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)

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 executive officer, 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 Risk Oversight Committee of 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 in which 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.

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 8 – 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, and transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by the traders and portfolio managers 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 a product of 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 forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is generally less than $4.00 and $0.25 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Item 3. – Quantitative and Qualitative Disclosures About Market Risk for information regarding the maturity by year of the Registrant's mark-to-market derivative assets and liabilities.

In 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 8 – Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.

Type of trade	Fair Value at September 30, 2012 (d)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	386	Discounted Cash Flow	Forward power price	$	8		-	$	76
			Discounted Cash Flow	Forward gas price	$	3.04		-	$	6.35
			Option Model	Volatility percentage		26	%	-		120	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	(83)	Discounted Cash Flow	Forward power price	$	13		-	$	108
			Option Model	Volatility percentage		22	%	-		67	%

Mark-to-market derivatives – Transactions with affiliates (Generation and ComEd) (b)	$	352	Discounted Cash Flow	Marketability reserve		7.3	%	-		8.7	%

Mark-to-market derivatives (ComEd)	$	(70)	Discounted Cash Flow	Forward heat rate (c)		8.5	%	-		9.5	%
				Marketability reserve		3.5	%	-		8.3	%
				Renewable factor		80	%	-		126	%

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 $352 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 below do not include cash collateral held on level three positions of $9 million as of September 30, 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 price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give 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.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Derivative Financial Instruments [Abstract]

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

9 Months Ended

Sep. 30, 2012

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

8. 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 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 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 18 of the Exelon 2011 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall energy marketing activities.

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. 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, 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.

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 September 30, 2012, the percentage of expected generation hedged was 98%-101%, 87%-90%, 55%-58% and 20%-23% for 2012, 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 excluding owned generation to be retired or sold in 2012. 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 2 of the Exelon 2011 Form 10-K, 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 2 of the Exelon 2011 Form 10-K 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 Program, which is further discussed in Note 4 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Program 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.

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 4,352 GWh and 9,981 GWh for the three and nine months ended September 30, 2012, respectively, and 1,679 GWh and 4,508 GWh for the three and nine months ended September 30, 2011, respectively, are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.

Interest Rate 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 interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. For interest rate hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying interest rate transaction occurs. For interest rate hedges that qualify and are designated as fair value hedges, only the ineffective portion of the derivative gain or loss will impact earnings. Assuming the fair value and cash flow hedges are effective, a hypothetical 50 bps increase in the interest rates associated with variable-rate debt and interest rate swaps would result in approximately $ 2 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2012. Below is a summary of the interest rate hedges as of September 30, 2012.

		Generation								Other		Exelon
Description		Derivatives Designated as Hedging Instruments		Economic Hedges (a)		Proprietary Trading (a)		Subtotal		Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	-	$	3	$	19	$	22	$	-	$	22
Mark-to-market derivative assets (Noncurrent Assets)		42		10		37		89		14		103
Total mark-to-market derivative assets	$	42	$	13	$	56	$	111	$	14	$	125

Mark-to-market derivative liabilities (Current Liabilities)	$	(1)	$	(2)	$	(19)	$	(22)	$	0	$	(22)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(36)		0		(37)		(73)		0		(73)
Total mark-to-market derivative liabilities	$	(37)	$	(2)	$	(56)	$	(95)	$	0	$	(95)

Total mark-to-market derivative net assets (liabilities)	$	5	$	11	$	0	$	16	$	14	$	30

(a) Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and 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 change in market interest rates.

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
		Nine Months Ended				Nine Months Ended
		September 30,				September 30,
Income Statement Classification		2012		2011		2012		2011
Interest expense (a)	$	(3)	$	1	$	(6)	$	(1)

__________

For the nine months ended September 30, 2012, the loss on the swaps in the table above includes pre-tax losses of $9 million, not related to changes in benchmark interest rates and is excluded from hedge ineffectiveness.

At September 30, 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 $55 million and $14 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 nine months ended September 30, 2012 and September 30, 2011, the impact of loss on the results of operations as a result of ineffectiveness from fair value hedges was immaterial.

At September 30, 2012, Exelon had $150 million of notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with 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 September 30, 2012, the impact on the results of operations was immaterial.

Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley acquisition, as discussed in Note 9 – 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 that 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 will be reflected in earnings. In order to mitigate this earnings impact, a series of offsetting hedge transactions will be 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 9 - Debt and Credit Agreements. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $119 million, 75% of the loan advance amount to offset portions of the original interest rate hedge, which are de-designated as a cash flow hedge. The remaining cash flow hedge has a notional amount of $365 million. At September 30, 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 $32 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 a solar project. The swaps have a total notional amount of $31 million as of September 30, 2012 and expire in 2027. Upon the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At September 30, 2012, the subsidiary had a $4 million non-current derivative liability related to these swaps.

During the three and nine months ended September 30, 2012 and 2011, the impact on the results of operations as a result of ineffectiveness from cash flow hedges 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 cash flow hedges, other derivatives 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 September 30, 2012:

		Generation								ComEd		Other			Exelon
		Generation								ComEd		Other			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)	$	3,399	$	3,694	$	(6,187)	$	906	$	0		$	0	$	906
Mark-to-market
	derivative assets with affiliate (current assets)		352		0		0		352		0			(352)		0
Mark-to-market
	derivative assets (noncurrent assets)		2,133		1,147		(2,343)		937		0			0		937

Total mark-to-market
	derivative assets	$	5,884	$	4,841	$	(8,530)	$	2,195	$	0		$	(352)	$	1,843

Mark-to-market
	derivative liabilities (current liabilities)	$	(2,951)	$	(3,675)	$	6,144	$	(482)	$	(17)		$	0	$	(499)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		(352)			352		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(1,369)		(1,106)		2,193		(282)		(53)			0		(335)

Total mark-to-market
	derivative liabilities	$	(4,320)	$	(4,781)	$	8,337	$	(764)	$	(422)		$	352	$	(834)

Total mark-to-market
	derivative net assets (liabilities)	$	1,564	$	60	$	(193)	$	1,431	$	(422)		$	0	$	1,009

__________

(a) Includes current assets for Generation and current liabilities for ComEd of $352 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described 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 $92 million and $263 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(49) million and $(113) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $193 million at September 30, 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:

		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 noncurrent 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.

Cash Flow Hedges (Exelon and Generation). 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 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. 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 $906 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 $383 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 2012 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, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the three months ended September 30, 2012 and 2011, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and nine months ended September 30, 2012, 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
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended September 30, 2012		Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30, 2012			$	923	(a)(c)	$	547
Reclassifications from accumulated OCI to net
	income	Operating Revenues		(171)	(b)		(88)	(d)
Ineffective portion recognized in income		Operating Revenues		0			0

Accumulated OCI derivative gain at September 30,
	2012		$	752	(a)(c)	$	459

(a) Includes $232 million and $315 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and June 30, 2012, respectively.

(b) Includes $83 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c) Excludes $22 million of losses and $22 million of losses net of taxes, related to interest rate swaps and treasury rate locks for the three months ended September 30, 2012 and three months ended June 30, 2012.

(d) Includes $0 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax

		Generation			Exelon
Nine Months Ended September 30, 2012	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2011		$	925	(a)(c)	$	488
Effective portion of changes in fair value			432	(e)		301	(d)
Reclassifications from accumulated OCI to net income	Operating Revenues		(608)	(b)		(332)
Ineffective portion recognized in income	Operating Revenues		3			3

Accumulated OCI derivative gain at September 30, 2012		$	752	(a)(c)	$	459

__________

(a) Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011.

(b) Includes $276 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c) Excludes $22 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury locks for the nine months ended September 30, 2012 and year ended December 31, 2011, respectively.

(d) Includes $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.

(e) Includes $88 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 through the date of de-designation prior to the merger.

			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended September 30, 2011		Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30,
	2011		$	688	(a) (d)	$	209
Effective portion of changes in fair value				(26)	(b)		(26)
Reclassifications from accumulated OCI to net
	income	Operating Revenues		(98)	(c)		(45)
Ineffective portion recognized in income		Purchased Power		7			7
Accumulated OCI derivative gain at September 30, 2011			$	571	(a)(d)	$	145

(a) Includes $400 million and $458 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2011 and June 30, 2011, respectively.

(b) Includes a $5 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended September 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in fair value of the block contracts with PECO for the three months ended September 30, 2011 as the mark-to-market balances previously recorded will be amortized over the term of the contract.

(c) Includes a $53 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended September 30, 2011.

(d) Excludes $6 million loss and $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2011 and June 30, 2011, respectively.

			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
				Generation			Exelon
Nine Months Ended September 30, 2011		Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at
	December 31, 2010			$	1,011	(a) (d)	$	400
Effective portion of changes in fair value					(69)	(b)		(73)
Reclassifications from accumulated OCI to
	net income	Operating Revenues			(373)	(c)		(184)
Ineffective portion recognized in income		Purchased Power			2			2
Accumulated OCI derivative gain at September 30 2011				$	571	(a)(d)	$	145

__________

(a) Includes $400 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2011 and December 31, 2010, respectively.

(b) Includes a $2 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the nine months ended September 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO's block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.

(c) Includes a $187 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the nine months ended September 30, 2011.

(d) Excludes $6 million loss and $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2011 and December 31, 2010.

During the three and nine months ended September 30, 2012, Generation's cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $283 million and a $ 1,005 million pre-tax gain, respectively, and a $162 million and $617 million pre-tax gain for the three and nine months ended September 30, 2011. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include 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 $5 million for the nine months ended September 30, 2012. There was no ineffectiveness for the three months ended September 30, 2012 as 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.

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 $145 million and $548 million pre-tax gain for the three and nine months ended September 30, 2012, respectively, and a $74 million and $305 million pre-tax gain for the three and nine months ended 2011, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices were $5 million for the nine months ended September 30, 2012. There was no ineffectiveness for the three months ended September 30, 2012 as 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 three and nine months ended September 30, 2012 and 2011, 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
Three Months Ended September 30, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(255)	$	129	$	(126)	$	35	$	(91)
Reclassification to realized at settlement		20		122		142		(19)		123
Net mark-to-market gains (losses)	$	(235)	$	251	$	16	$	16	$	32

	Generation							Intercompany Eliminations	Exelon
				Purchased
	Operating			Power				Operating
Nine Months Ended September 30, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(85)	$	121	$	36	$	62	$	98
Reclassification to realized at settlement		(81)		326		245		(29)		216
Net mark-to-market gains (losses)	$	(166)	$	447	$	281	$	33	$	314

	Exelon and Generation
				Purchased
	Operating			Power
Three Months Ended September 30, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	22	$	22
Reclassification to realized at settlement		0		(101)		(101)
Net mark-to-market (losses) (b)	$	0	$	(79)	$	(79)

	Exelon and Generation
				Purchased
	Operating			Power
Nine Months Ended September 30, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	13	$	13
Reclassification to realized at settlement		0		(372)		(372)
Net mark-to-market (losses) (b)	$	0	$	(359)	$	(359)

	Exelon and Generation
				Purchased
	Operating			Power
Three Months Ended September 30, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	31	$	(9)	$	22
Reclassification to realized at settlement		(105)		4		(101)
Net mark-to-market (losses) (b)	$	(74)	$	(5)	$	(79)

	Exelon and Generation
				Purchased
	Operating			Power
Nine Months Ended September 30, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	44	$	(31)	$	13
Reclassification to realized at settlement		(374)		2		(372)
Net mark-to-market (losses) (b)	$	(330)	$	(29)	$	(359)

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 three and nine months ended September 30, 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.

		Three Months Ended				Nine Months Ended
	Location on Income	September 30,				September 30,
	Statement	2012		2011		2012		2011
Change in fair value	Operating Revenue	$	(2)	$	2	$	12	$	22
Reclassification to realized at
settlement	Operating Revenue		25		(6)		57		(19)

Net mark-to-market gains	Operating Revenue	$	23	$	(4)	$	69	$	3

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 and risk management capabilities. To the extent that a counterparty's margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation's credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation's credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 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 RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $53 million, $53 million and $11 million, respectively.

	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of September 30, 2012	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,968	$	492	$	1,476		0	$	0
Non-investment grade		46		25		21		0		0
No external ratings
Internally rated - investment grade		501		16		485		1		267
Internally rated - non-investment
grade		90		2		88		0		0
Total	$	2,605	$	535	$	2,070		1	$	267

Net Credit Exposure by Type of Counterparty	As of September 30, 2012

Investor-owned utilities, marketers and power producers		$	902
Energy cooperatives and municipalities			710
Financial institutions			386
Other			72
Total		$	2,070

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 September 30, 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 2 of the Exelon 2011 Form 10-K 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 September 30, 2012, PECO had no net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 - 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 $14 million in parental guarantees related to these agreements. As of September 30, 2012, PECO had credit exposure of $8 million under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 6 of BGE's 2011 Form 10-K 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 September 30, 2012, BGE had no net credit exposure to suppliers.

BGE's regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE's recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers' demand, which are not covered by the gas cost adjustment clause. At September 30, 2012, BGE had credit exposure of $1 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 and emissions allowances. Certain of Generation's derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on NYMEX, ICE, and Nodal Exchanges (“the exchanges”). 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. 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		September 30, 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)


($2,720)	$2,156	($564)


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 $415 million and letters of credit posted of $973 million and cash collateral held of $607 million and letters of credit held of $109 million as of September 30, 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 $2,004 million as of September 30, 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 interest rate swaps contain provisions that, in the event of a merger, if Generation's debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2012, Generation's swaps were in an asset position, with a fair value of $16 million.

See Note 18 of the Exelon 2011 Form 10-K 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 September 30, 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 September 30, 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 2 of the Exelon 2011 Form 10-K 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 September 30, 2012, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2012, PECO could have been required to post approximately $30 million of collateral to its counterparties.

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

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

BGE's natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2012, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2012, BGE could have been required to post approximately $51 million of collateral to its counterparties.

Exelon's interest rate swaps contain provisions that, in the event of a merger, if Exelon's debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date less charges. As of September 30, 2012, Exelon's swaps were in an asset position, with a fair value of $30 million.

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

As of September 30, 2012 and December 31, 2011, $1 million of cash collateral posted and $2 million of cash collateral received was not offset against derivative positions because they were not associated with energy-related derivatives.

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.

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Debt and Credit Agreements [Abstract]

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

9 Months Ended

Sep. 30, 2012

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

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

Short-Term Borrowings

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

The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2012 and December 31, 2011:

Credit Facilities

Exelon had bank lines of credit under committed credit facilities at September 30, 2012 for short-term financial needs, as follows:

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolvers	$	2.0	December 2012 and August 2017	Letters of credit and cash
Generation
	Syndicated Revolver		5.3	August 2017	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2017	Letters of credit and cash
PECO
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
BGE
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
	Total	$	9.8

_____________

Excludes $118 million of credit facility agreements arranged with minority and community banks at Generation, ComEd and PECO. These facilities, which expired and were replaced in October 2012, were solely utilized to issue letters of credit.

As of September 30, 2012, there were no borrowings under the Registrants' credit facilities.

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 3 – Merger and Acquisitions for further description of the merger transaction.

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 amend and extend the facilities for ComEd were not material.

Borrowings under the credit agreement may bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon ComEd's credit rating. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The fee varies depending upon ComEd's credit rating. The credit agreement also requires ComEd to pay a facility fee based upon the aggregate commitments under the agreement.

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 such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material.

The amended credit facilities updated the credit ratings-based pricing grids used to determine the facility fee and interest rates for borrowings under each facility and reflect current market pricing and maturities of five years from the close of the transactions. Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon the prime rate or upon a LIBOR-based rate. Exelon Corporate, Generation, PECO and BGE have adders of 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. 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 covenants in each of Exelon Corporate, Generation, PECO and BGE's extended facilities are substantially consistent with existing covenants, with the exception of the BGE facility, in which a debt to capitalization financial covenant was replaced with an interest coverage ratio financial covenant.

On October 19, 2012, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements 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 to issue letters of credit.

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 are 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 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 September 30, 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 September 30, 2012;
$450 million aggregate principal amount of 8.625% Series A Junior Subordinated Debentures due 2063, all of which was outstanding as of September 30, 2012; and
$550 million aggregate principal amount of 5.15% Notes due 2020, all of which was outstanding as of September 30, 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 $212 million was outstanding as of September 30, 2012, primarily reflecting the Exchange Offer described above. This premium is being amortized over the lives of the arrangements as a reduction to interest expense.

Generation filed a registration statement on Form S-4 on November 1, 2012 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 registered notes will have the same terms and maturity dates as the privately placed senior notes.

Issuance of Long-Term Debt

During the nine months ended September 30, 2012, the following long-term debt was issued:

Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Senior Notes	4.250	%	June 15, 2022	$	523	Used for general corporate purposes and issued in connection with the Exchange Offer
Generation	Senior Notes	5.600	%	June 15, 2042	$	788	Used for general corporate purposes and issued in connection with the Exchange Offer
Generation	CEU Credit Agreement	1.990	%	June 16, 2016	$	43	Used to fund Upstream gas activities
Generation	DOE Project Financing	2.330 - 3.092	%	January 5, 2037	$	100	Funding for Antelope Valley solar development
Generation	Clean Horizons	2.500	%	June 7, 2030	$	38	Funding for Maryland solar development
BGE	Notes	2.800	%	August 15, 2022	$	250	Used to repay total outstanding commercial paper and for general corporate purposes
PECO	First and Refunding Mortgage Bonds	2.375	%	September 15, 2022	$	350	Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes

On October 1, 2012, ComEd issued $350 million aggregate principal of its First Mortgage 3.80% Bonds, Series 113 due October 1, 2042. ComEd will use the net proceeds from the sale of the bonds to repay outstanding commercial paper obligations and for general corporate purposes.

During October 2012, Antelope Valley received DOE-guaranteed loan advances of $59 million at 2.482% and $2 million at 2.595%, due January 5, 2037.

During the nine months ended September 30, 2011, the following long-term debt was issued:

Company	Type	Interest Rate	Maturity		Amount	Use of Proceeds
ComEd	First Mortgage Bonds	1.625%	January 15, 2014	$	600	Used as an interim source of liquidity for January 2011 contribution for Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes.
ComEd	First Mortgage Bonds (a)	1.950%	September 1, 2016	$	250	To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011.
ComEd	First Mortgage Bonds (a)	3.400%	September 1, 2021	$	350	To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011.

________________

As of September 30, 2011, $536 million of the total proceeds from the issuances of First Mortgage Bonds due September 1, 2016 and September 1, 2021 was reflected in restricted cash on Exelon's and ComEd's Consolidated Balance Sheets for the purpose of redeeming outstanding debt under ComEd's long-term debt refinancing authority with the ICC.

Retirement of Current and Long-Term Debt

During the nine months ended September 30, 2012, the following current and long-term debt was retired:

Company	Type	Interest Rate		Maturity	Amount
ComEd	First Mortgage Bond Series 98	6.15	%	March 15, 2012		$	450
BGE	Rate Stabilization Bonds	5.68	%	April 1, 2017		$	31
BGE	Medium Term Notes	6.73 - 6.75	%	June 15, 2012		$	110
Generation	Armstrong Co. tax-exempt	5.00	%	December 1, 2042		$	46
Generation	CEU Credit Agreement	2.27	%	June 16, 2016		$	3
Generation	MEDCO Tax-Exempt Bonds	Variable		April 1, 2024		$	75
Generation	Solar Revolver	2.49	%	July 7, 2014		$	13
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
Exelon	Senior Notes	7.60	%	April 1, 2032		$	442
Exelon	Medium Term Notes	7.30	%	June 1, 2012		$	2

On October 1, 2012, PECO retired $225 million aggregate principal of its 4.750% First and Refunding Mortgage Bonds due October 1, 2012.

On October 1, 2012, BGE retired $32 million aggregate principal of its 5.680% Rate Stabilization Bonds due April 1, 2017.

During the nine months ended September 30, 2011, the following long-term debt was retired:

Company	Type	Interest Rate		Maturity	Amount
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
ComEd	Sinking fund debentures	4.75	%	December 1, 2011			1

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, which is classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets. As of September 30, 2012 and December 31, 2011, the financial institution's undivided interest in Exelon's and PECO's gross accounts receivable was equivalent to $314 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 criteria for eligible receivables to include receivables that have been purchased by PECO and revises the compliance criteria for the eligible asset test to allow for the payment of capital within a specified period of time. As of September 30, 2012, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and may seek alternate financing.

Antelope Valley Project Development Debt Agreement

On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million at an interest rate spread of 37.5 basis points above U.S. Treasury and maturity of January 5, 2037. 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 September 30, 2012, has received $100 million in DOE-guaranteed funding. See Note 8 – Derivative Financial Instruments for additional information on the interest rate swap related to the loan advances and Note 3 – Mergers and Acquisitions for additional information on the transaction.

In addition, Generation has issued letters of credit to support its equity investment in the project. As of September 30, 2012, Generation had $656 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.

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.

Income Taxes (Exelon, Generation, ComEd and PECO)

Income Taxes (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

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

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:

For the Three Months Ended September 30, 2012		Exelon (a)		Generation (a)		ComEd		PECO		BGE (b)

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	0.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	5.6		5.9		5.0		3.0		0.0
	Qualified nuclear decommissioning trust fund income	7.8		21.5		0.0		0.0		0.0
	Domestic production activities deduction	0.3		0.8		0.0		0.0		0.0
	Tax exempt income	(0.2)		(0.5)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		0.6		0.0		0.0
	Amortization of investment tax credit, net deferred taxes	(4.8)		(13.0)		(0.5)		(0.3)		0.0
	Plant basis differences	(4.7)		0.0		(0.5)		(21.0)		0.0
	Production tax credits	(2.5)		(7.4)		0.0		0.0		0.0
	Fines & penalties	(0.1)		0.0		0.0		0.0		0.0
	Other (d)	(1.2)		7.1		0.0		0.2		0.0

Effective income tax rate		35.2	%	49.4	%	39.6	%	16.9	%	0.0	%

For the Nine Months Ended September 30, 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	(4.7)		2.5		5.4		3.2		2.3
	Qualified nuclear decommissioning trust fund income	6.9		10.9		0.0		0.0		0.0
	Tax exempt income	(0.3)		(0.5)		0.0		0.0		0.0
	Health Care Reform Legislation	0.2		0.0		0.6		0.0		(4.6)
	Amortization of investment tax credit, net deferred taxes	(2.3)		(3.3)		(0.5)		(0.3)		2.9
	Plant basis differences	(2.2)		0.0		(0.2)		(9.7)		7.2
	Production tax credits	(2.6)		(4.3)		0.0		0.0		0.0
	Fines & penalties	3.8		6.0		0.0		0.0		0.0
	Merger expenses (c)	3.6		0.0		0.0		0.0		(14.0)
	Other	(1.3)		0.8		0.2		(0.0)		4.5

Effective income tax rate		36.1	%	47.1	%	40.5	%	28.2	%	33.3	%


For the Three Months Ended September 30, 2011		Exelon		Generation		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	4.8		5.5		0.8		2.9		6.2
	Qualified nuclear decommissioning trust fund income	(6.4)		(10.2)		0.0		0.0		0.0
	Domestic production activities deduction	1.0		1.7		0.0		0.0		0.0
	Tax exempt income	(0.1)		(0.2)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		0.3		0.0		(16.4)
	Amortization of investment tax credit	(0.3)		(0.2)		(0.5)		(0.3)		13.8
	Plant basis differences	(3.2)		0.0		(0.7)		(23.8)		48.4
	Production tax credits	(1.1)		(1.7)		0.0		0.0		0.0
	Interest and penalties on unrecognized tax benefits (e)	0.0		0.0		0.0		0.0		137.8
	Other	0.1		0.3		0.4		0.1		75.2

Effective income tax rate		29.8	%	30.2	%	35.3	%	13.9	%	300.0	%

For the Nine Months Ended September 30, 2011		Exelon		Generation		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	4.1		4.9		3.4		(0.4)		4.8
	Qualified nuclear decommissioning trust fund income	(0.6)		(0.8)		0.0		0.0		0.0
	Domestic production activities deduction	(0.4)		(0.6)		0.0		0.0		0.0
	Tax exempt income	(0.1)		(0.2)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		(1.5)		0.0		(0.8)
	Amortization of investment tax credit	(0.3)		(0.2)		(0.4)		(0.3)		(0.5)
	Plant basis differences	(1.0)		0.0		(0.4)		(6.8)		(1.6)
	Production tax credits	(1.0)		(1.4)		0.0		0.0		0.0
	Interest and penalties on unrecognized tax benefits (e)	0.0		0.0		0.0		0.0		(1.1)
	Other	(0.3)		(0.9)		0.3		0.0		(0.1)

Effective income tax rate		35.4	%	35.8	%	36.4	%	27.5	%	35.7	%

__________

(a) Exelon activity for the three and nine months ended September 30, 2012 includes the results of Constellation and BGE for March 12, 2012 - September 30, 2012. Generation activity for the three and nine months ended September 30, 2012 includes the results of Constellation for March 12, 2012 - September 30, 2012.

(b) BGE activity represents the activity for the three and nine months ended September 30, 2012 and 2011. BGE activity for the three months ended September 30, 2012 resulted in zero pre-tax income and zero income taxes. BGE recognized a loss before income taxes for the nine months ended September 30, 2012 and three months ended September 30, 2011. As a result, positive percentages represent an income tax benefit for BGE for the nine months ended September 30, 2012 and three months ended September 30, 2011.

(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.

(d) For the three months ended September 31, 2012, Generation's effective tax rate was affected by the resolution of uncertain Federal tax positions (5.3%), the finalization of prior year tax return calculations 4.2%, changes in the forecasted activity attributable to noncontrolling interests 4.1%, and other 4.1%.

(e) Until March 12, 2012, BGE recorded interest and penalties relating to unrecognized tax benefits as tax expense.

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd, PECO, and BGE have $980 million, $829 million, $68 million, $44 million, and $0 million, respectively, of unrecognized tax benefits as of September 30, 2012. Exelon's, Generation's, ComEd's, PECO's and BGE's uncertain tax positions have not significantly changed since December 31, 2011. See Note 11 of the Exelon 2011 Form 10-K and Note 10 of the 2011 Form 10-K for Constellation and BGE for further discussion of reasonably possible changes that could occur in unrecognized tax benefits during the next twelve months.

Other Income Tax Matters

IRS Appeals 1999-2001 (Exelon, ComEd and PECO)

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 1999 sale of ComEd's fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. 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. Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction.

Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd's and PECO's transition periods represented compensation for a taking of their respective properties 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 Tax Positions. In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon's involuntary conversion and CTC positions. The agreement includes IRS Appeals' agreement to withdraw its assertion of the $110 million substantial understatement penalty with respect to Exelon's involuntary conversion position. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits associated with the settled positions and established a current tax payable to the IRS. Exelon has received verbal confirmation from the IRS that the Joint Committee on Taxation has approved the terms of the preliminary agreement and Exelon expects final IRS approval in the fourth quarter of 2012.

Under the terms of the agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2012 for the years for which there is a resulting tax deficiency, of which $405 million is attributable to ComEd, ($135) million to PECO, $10 million to Generation and the remainder to Exelon. These amounts are net of approximately $300 million of refunds due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM as well as other agreed upon audit adjustments. In order to stop additional interest from accruing on the expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million.

Exelon and IRS Appeals to date have failed to reach a settlement with respect to 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. Exelon continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS in its settlement offer reflects the strength of Exelon's position. IRS Appeals also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position.

While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has thus far been unwilling to settle the issue without requiring a nearly complete concession of the issue by Exelon. Accordingly, to continue to contest the IRS's disallowance of the like-kind exchange position and its assertion of the $86 million substantial understatement penalty, Exelon expects to initiate litigation in 2013. Given that Exelon has determined settlement is not a realistic outcome, it has assessed, in accordance with applicable accounting standards, whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and, therefore, eliminated any liability for unrecognized tax benefits. Further, Exelon believes it is unlikely that the penalty assertion will ultimately be sustained. Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty, it would result in an after-tax charge of $86 million to Exelon's and ComEd's results of operations.

As of September 30, 2012, assuming Exelon's settlement of the involuntary conversion position is finalized, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully successful IRS challenge to Exelon's like-kind exchange position could be as much as $870 million, of which $510 million would be paid by ComEd and the remainder by Exelon. If the IRS were to prevail in litigation on the like-kind exchange position, Exelon's results of operations could be negatively affected due to increased interest expense, as of September 30, 2012, by as much as $260 million, net of tax, of which $160 million would be recorded at ComEd and the remainder by Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.

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 their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, such as the merger with Constellation. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they have state income tax obligations, which include 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 first quarter of 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 first quarter of 2012.

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 through Q3 2012 resulted in a tax benefit of $19 million at Exelon, of which $22 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. Exelon currently anticipates that the IRS will issue guidance in the near future providing a safe harbor method of tax accounting for gas transmission and distribution property.

Interest Expense on Income Taxes (BGE)

For the three and nine months ended September 30, 2012, BGE recorded an adjustment to interest expense of approximately $2 million and $9 million, respectively, to reflect the impacts of anticipated amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded this adjustment is not material to its results of operations or cash flows for the three and nine months ended September 30, 2012, or any prior period.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: 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 3: 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.

Reference 4: 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 5: 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 6: 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 7: 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 8: 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

Asset Retirement Obligations [Abstract]

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

9 Months Ended

Sep. 30, 2012

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

11. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets from December 31, 2011 to September 30, 2012:

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

(a) Includes $6 million and $5 million as the current portion of the ARO at September 30, 2012 and December 31, 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

During the nine months ended September 30, 2012, Generation's ARO increased by $916 million. The increase in the ARO is largely driven by 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 CARFRs, which have dramatically decreased given the current low interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities and Dresden 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 the third quarter of 2011, Generation recorded a net increase in the ARO of $176 million primarily due to 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 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.

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 may 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. On March 30, 2012, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of $24 million, which reflects a reduction from the current approved annual collections of $29 million. On July 23, 2012, the PAPUC approved the filing and the new rates will be effective January 1, 2013. See Note 12 of the Exelon 2011 Form 10-K for information regarding amounts collected from PECO customers for decommissioning costs. See below for discussion of NRC minimum funding requirements.

In the first half of 2012, the NDT fixed income portfolio completed the transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and short-term corporate lending. There was no change in the equity investment strategy.

At September 30, 2012 and December 31, 2011, Exelon and Generation had NDT fund investments totaling $7,140 million and $6,507 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2012 and 2011:

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

(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 $22 million of net unrealized gains and $4 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2012 and 2011, respectively, and $60 million and $41 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.

(c) Net unrealized gains (losses) related to Generation's NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units, which are subject to regulatory accounting, are eliminated within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income.

See Note 2 of the Exelon 2011 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 12 of the Exelon 2011 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. On July 14, 2011, four 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's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. 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 $78 million, which is included within the nuclear decommissioning ARO at September 30, 2012. Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of September 30, 2012, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $631 million and $582 million, respectively. The payable excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Exelon's and Generation's Consolidated Balance Sheets at September 30, 2012 and December 31, 2011 was $160 million and $128 million, respectively.

NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. On 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.

Nuclear Decommissioning (Exelon and Generation)

9 Months Ended

Sep. 30, 2012

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

11. Nuclear Decommissioning (Exelon and Generation)

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 December 31, 2011 to September 30, 2012:

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

Nuclear Decommissioning Trust Fund Investments

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

11. Nuclear Decommissioning (Exelon and Generation)

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 December 31, 2011 to September 30, 2012:

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

Nuclear Decommissioning Trust Fund Investments

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

Retirement Benefits (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2012

Retirement Benefits [Abstract]

Retirement Benefits (Exelon, Generation, ComEd and PECO)

12. 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. As of that date, the legacy Constellation pension and other postretirement benefit plans were remeasured using current assumptions including the discount rate.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2012, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2012. This valuation resulted in an increase to the pension and other postretirement benefit obligations of $86 million and $25 million, respectively. Additionally, accumulated other comprehensive loss increased by approximately $8 million (after tax) and regulatory assets increased by $98 million.

During the second quarter of 2012, Exelon received an updated valuation of legacy Constellation's pension and postretirement benefit obligations to reflect actual census data as of the merger date. This valuation resulted in an increase and a decrease to the pension and other postretirement benefit obligations of $1 million and $19 million, respectively. Additionally, accumulated other comprehensive loss decreased by approximately $3 million (after-tax) and regulatory assets decreased by approximately $13 million.

As a result of employee severances related to the merger, a curtailment was triggered for certain legacy Constellation pension and other postretirement benefit plans in the second quarter of 2012. Accordingly, the benefit obligation and plan assets for those plans were remeasured using assumptions as of June 30, 2012, including updated discount rates, asset values, and planned changes to the method of obtaining prescription drug subsidies. The discount rates used to calculate the curtailed pension and other postretirement benefit plan obligations as of June 30, 2012 were 3.97% and 3.98%, respectively. The curtailment and associated remeasurement resulted in an increase and a decrease to the pension and other postretirement benefit obligations of $84 million and $32 million, respectively. Additionally, accumulated other comprehensive loss increased by approximately $6 million (after-tax) and regulatory assets increased by approximately $44 million. Exelon also recognized a $2 million curtailment gain for legacy Constellation's other postretirement benefit plans in the second quarter of 2012, of which Generation recognized a $1 million curtailment gain.

Under Exelon's and Constellation's severance plans, certain severed employees were offered additional pension and other postretirement benefits. As a result, Exelon recorded contractual termination benefit charges of $20 million in the second quarter of 2012, of which Generation and BGE recorded $9 million and $3 million, respectively. BGE recorded its portion of the contractual termination benefit charge of $3 million along with $1 million that was billed to it by BSC as a regulatory asset, consistent with prior MDPSC precedent. ComEd recorded the $1 million of contractual termination benefit charge that was billed to it by BSC as a regulatory asset pursuant to EIMA.

During the third quarter of 2012, Exelon announced plan design changes for certain other postretirement benefit plans, requiring an interim remeasurement of the benefit obligation and assets for those plans using assumptions as of September 30, 2012, including updated discount rates and asset values. The discount rates used to calculate the other postretirement benefit plan obligations for legacy Exelon and Constellation were 3.93% and 3.72%, respectively, as of September 30, 2012. The remeasurement resulted in an increase to the other postretirement benefit obligation, accumulated other comprehensive loss, and regulatory assets of $212 million, $68 million (after-tax), and $99 million, respectively. Additionally, Exelon recognized a $5 million curtailment gain in the third quarter of 2012 related to these plan design changes, of which Generation and BGE recognized a curtailment gain of $1 million and $3 million, respectively.

The following tables present the components of Exelon's net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011. The 2012 pension benefit cost for legacy Exelon plans was calculated using an expected long-term rate of return on plan assets of 7.50% and a discount rate of 4.74%. The 2012 pension benefit cost for legacy Constellation plans was calculated using an expected long-term rate of return on plan assets of 7.50% and discount rates of 4.27% and 3.97% for the period post-merger through June 30, 2012 and July 1, 2012 through September 30, 2012, respectively. The 2012 other postretirement benefit cost for legacy Exelon plans was calculated using an expected long-term rate of return on plan assets of 6.68% and a discount rate of 4.80%. The 2012 other postretirement benefit cost for legacy Constellation plans was calculated using a discount rate of 4.28% and 3.98% for the period post-merger through June 30, 2012 and July 1, 2012 through September 30, 2012, respectively. Legacy Constellation other postretirement benefit plans are not funded. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

			Pension Benefits				Other Postretirement Benefits
			Three Months Ended				Three Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Service cost		$	76	$	53	$	38	$	36
Interest cost			181		162		53		52
Expected return on assets			(258)		(235)		(28)		(27)
Amortization of:
	Transition obligation		0		0		2		2
	Prior service cost (benefit)		5		4		(3)		(10)
	Actuarial loss		117		83		19		16
Settlement Charges			9		0		0		0
Curtailment gain			0		0		(5)		0

Net periodic benefit cost		$	130	$	67	$	76	$	69

			Pension Benefits				Other Postretirement Benefits
			Nine Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Service cost		$	211	$	159	$	114	$	107
Interest cost			524		487		157		155
Expected return on assets			(742)		(704)		(86)		(83)
Amortization of:
	Transition obligation		0		0		8		7
	Prior service cost (benefit)		12		11		(10)		(29)
	Actuarial loss		338		248		58		49
Settlement Charges			9		0		0		0
Contractual termination benefit cost (a)			14		0		6		0
Curtailment gain			0		0		(7)		0

Net periodic benefit cost		$	366	$	201	$	240	$	206

(a) As discussed above, ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge.

The amounts below were included in capital additions and operating and maintenance expense during the three and nine months ended September 30, 2012 and 2011, for Generation's, ComEd's, PECO's, BGE's and BSC's allocated portion of the pension and postretirement benefit plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Pension and Postretirement Benefit Costs	2012		2011		2012		2011
Generation	$	85	$	64	$	259	$	187
ComEd		75		53		212		160
PECO		12		8		38		24
BGE (a)(b)		14		15		46		43
BSC (c)		20		11		63		36

(a) BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's pension and postretirement benefit costs for the three months and nine months ended September 30, 2011 were $15 million and $43 million, respectively. These amounts are not included in Exelon's net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above.

(b) BGE's pension and other postretirement benefit costs for the nine months ended September 30, 2012 includes a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of September 30, 2012.

(c) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of September 30, 2012, ComEd and BGE each recorded a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge.

During the fourth quarter of 2012, Exelon will record an additional settlement charge of approximately $17 million. This charge is triggered by lump sum payments made to executives during the fourth quarter of 2012.

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon expects to contribute $77 million to its qualified pension plans in 2012, of which Generation, ComEd, and PECO will contribute $46 million, $9 million, and $13 million, respectively. Legacy Constellation's 2011 pension contributions included an acceleration of estimated calendar year 2012 contributions. Therefore, BGE does not anticipate any qualified pension contributions in 2012. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $67 million in 2012, of which Generation, ComEd, PECO, and BGE will make payments of $9 million, $14 million, $1 million, and $1 million, respectively.

Unlike qualified pension plans, other postretirement plans are not subject to regulatory minimum contribution requirements. Exelon's management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). In 2012, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans previously sponsored by Constellation and AmerGen, which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $318 million in 2012, of which Generation, ComEd, PECO, and BGE expect to contribute $131 million, $116 million, $33 million, and $13 million, respectively. This total excludes $4 million in 2012 other postretirement benefit plan contributions by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012.

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented 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.

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2012 and 2011:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Savings Plan Matching Contributions	2012		2011		2012		2011
Exelon	$	16	$	26	$	49	$	64
Generation		7		13		23		33
ComEd		5		8		14		18
PECO		2		3		5		7
BGE (a)		1		1		5		5
BSC (b)		1		2		3		6

BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012.
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

The entire disclosure for pension and other postretirement benefits.

Reference 1: 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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
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Corporate Restructuring And Plant Retirements [Abstract]

Plant Retirements (Exelon and Generation)

9 Months Ended

Sep. 30, 2012

Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

13. 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. PJM has 30 days to review whether the proposed retirements of the units create transmission system reliability issues. Once PJM's review is complete, Exelon will determine final retirement dates for the units. The impact of the early retirements will not have a material impact on Generation or Exelon's results of operations, cash flows or financial position.

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 May 31, 2011 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 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 was approximately $6 million. Such revenue was intended to recover total expected operating costs, plus a return on net assets, of the unit during the reliability-must-run period. In addition, Generation was 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 operated under the reliability-must-run agreement from June 1, 2011 until the May 31, 2012 retirement date. See Note 14 of the Exelon 2011 Form 10-K for additional information.

The following table presents the activity of severance obligations for the announced Eddystone and Cromby retirements from December 31, 2011 through September 30, 2012:

Severance Benefits Obligation		Exelon and Generation
Balance at December 31, 2011	$	7
Cash payments		(2)

Balance at September 30, 2012	$	5

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.

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

9 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

14. Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At September 30, 2012, there were approximately 20 million shares authorized for issuance under the LTIP. For the three and nine months ended September 30, 2012 and 2011, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

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 3 - 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 and Comprehensive Income for the three and nine months ended September 30, 2012 and 2011:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,

Components of Stock-Based Compensation Expense		2012		2011		2012		2011

Performance share awards		$	5	$	6	$	32	$	17
Stock options			2		1		13		7
Restricted stock units			12		5		41		26
Other stock-based awards			1		1		3		3

Total stock-based compensation expense included in
	operating and maintenance expense		20		13		89		53

Income tax benefit			(8)		(5)		(34)		(21)

Total after-tax stock-based compensation expense		$	12	$	8	$	55	$	32

The following table presents stock-based compensation expense for the three and nine months ended September 30, 2012 and 2011:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

Subsidiaries	2012		2011		2012		2011

Generation	$	9	$	6	$	33	$	24
ComEd		2		1		9		4
PECO		1		1		4		4
BGE (a)		1		0		4		0
BSC (b)		7		5		39		21

Total	$	20	$	13	$	89	$	53

(a) BGE's stock-based compensation expense for the nine months ended September 30, 2012 includes $2 million of cost incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the nine months ended September 30, 2012 shown in the table titled Components of Stock-Based Compensation Expense above. BGE's stock-based compensation expense for the three and nine months ended September 30, 2011 was $1 million and $5 million, respectively.

(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 three and nine months ended September 30, 2012 and 2011.

Stock Options

Non-qualified stock options are granted under the LTIP with exercise prices equal to the fair market value of the underlying stock at the date of grant. Generally, the stock options vest ratably over a four-year vesting period and expire ten years from the date of grant.

The following table presents the weighted average assumptions used to value Exelon stock options at their grant date for the three and nine months ended September 30, 2012 and 2011:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,

	2012			2011			2012			2011

Dividend yield		5.28	%		4.84	%		5.28	%		4.84	%
Expected volatility		23.20	%		24.40	%		23.20	%		24.40	%
Risk-free interest rate		1.30	%		2.65	%		1.30	%		2.65	%
Expected life (years)		6.25			6.25			6.25			6.25

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 nine months ended September 30, 2012.

The following table summarizes Exelon's stock option activity for the nine months ended September 30, 2012:

		Weighted Average
		Exercise Price
	Shares	(per share)

Balance of shares outstanding at December 31, 2011	11,553,761	$	48.49
Granted	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Exercised	(1,575,275)		26.57
Forfeited	(28,142)		44.88
Expired	(488,434)		48.59

Balance of shares outstanding at September 30, 2012	23,028,061	$	45.61

Exercisable at September 30, 2012 (a)	20,962,469	$	46.08

(a) Includes stock options issued to retirement eligible employees.

The following table summarizes Exelon's nonvested stock option activity for the nine months ended September 30, 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)	(11,889,175)		41.39
Forfeited	(488,434)		48.59

Nonvested at September 30, 2012 (a)	2,065,592	$	40.60

(a) Excludes 2,719,671 and 1,348,000 of stock options issued to retirement-eligible employees as of September 30, 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 1,667,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.

At September 30, 2012, $8 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2.5 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 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 following table summarizes Exelon's nonvested restricted stock unit activity for the nine months ended September 30, 2012:


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	1,074,484	$	48.08
Granted	1,283,292		39.93
Converted Constellation restricted stock	825,735		38.91
Vested	(427,499)		47.69
Forfeited	(47,415)		42.67
Undistributed vested awards (b)	(602,276)		40.53

Nonvested at September 30, 2012 (a)	2,106,321	$	42.27

(a) Excludes 656,228 and 448,827 of restricted stock units issued to retirement-eligible employees as of September 30, 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.

At September 30, 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of $58 million, which are included in common stock in Exelon's Consolidated Balance Sheets. As of September 30, 2012, Exelon had no obligations related to outstanding restricted stock units that will be settled in cash. During the three months ended September 30, 2012 and 2011, Exelon settled restricted stock units with a fair value totaling $4 million and $1 million, respectively. During the nine months ended September 30, 2012 and 2011, Exelon settled restricted stock units with a fair value totaling $23 million and $19 million, respectively. At September 30, 2012, $54 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.08 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.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance shares granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant.

The following table summarizes Exelon's nonvested performance share awards activity for the nine months ended September 30, 2012:


		Weighted Average
		Grant Date Fair
	Shares	Value (per share)

Nonvested at December 31, 2011 (a)	346,848	$	45.37
Granted	1,249,932		39.73
Vested	(159,194)		47.66
Forfeited	(113,761)		39.79
Undistributed vested awards (b)	(128,370)		40.98

Nonvested at September 30, 2012 (a)	1,195,455	$	40.17

(a) Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of September 30, 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.

During the three months ended September 30, 2012 and 2011, the fair value of Exelon's settled performance shares and payments made in cash were immaterial. During the nine months ended September 30, 2012 and 2011, Exelon settled performance shares with a fair value totaling $22 million and $21 million, respectively, of which $3 million and $10 million was paid in cash, respectively. As of September 30, 2012, $19 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.3 years.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
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-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
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-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

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Earnings Per Share and Equity [Abstract]

Earnings Per Share and Equity (Exelon)

9 Months Ended

Sep. 30, 2012

Earnings Per Share and Equity (Exelon)

15. 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 (in millions) used in calculating diluted earnings per share:

			Three Months Ended September 30,				Nine Months Ended September 30,
			2012		2011		2012		2011

Net income on common stock		$	296	$	601	$	782	$	1,889

Average common shares outstanding — basic			854		663		804		663
Assumed exercise of stock options, performance share awards
	and restricted stock		3		2		2		1

Average common shares outstanding — diluted			857		665		806		664

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 18 million and 13 million for the three and nine months ended September 30, 2012, respectively, and 10 million and 9 million for the three and nine months ended September 30, 2011, respectively.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2012. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

9 Months Ended

Sep. 30, 2012

Commitments And Contingencies [Abstract]

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

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

The following is an update to the current status of commitments and contingencies set forth in Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation's and BGE's 2011 Form 10-K.

Commitments

Energy Commitments

As of September 30, 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 table:

	Net Capacity			Power-Related			Transmission Rights			Purchased Energy
	Purchases (a)			Purchases (b)			Purchases (c)			from CENG			Total

2012		$	111		$	8		$	8		$	148		$	275
2013			375			92			32			699			1,198
2014			352			62			26			451			891
2015			350			23			13			—			386
2016			266			9			2			—			277
Thereafter			672			8			36			—			716

Total		$	2,126		$	202		$	117		$	1,298		$	3,743

(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at September 30, 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.

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 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 ##CEGINV – Investment in Constellation energy Nuclear Group, LLC for more details on this arrangement.

ComEd's, PECO's and BGE's electric supply procurement, curtailment services, REC and AEC purchase commitments as of September 30, 2012 are as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

ComEd
Electric supply procurement (a)	$	1,103	$	-	$	367	$	323	$	136	$	137	$	140
Renewable energy and RECs (b)		1,694		33		71		73		74		76		1,367
PECO
Electric supply procurement (c)		789		210		413		130		36		-		-
AECs		35		3		11		9		2		2		8
Curtailment services		4		4		-		-		-		-		-
BGE
Electric supply procurement (d)		1,171		201		707		263		-		-		-
Curtailment services		165		11		49		47		41		17		-

(a) ComEd entered into various contracts for the procurement of electricity that expire between 2012 and 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 4 - Regulatory Matters for additional information.

(b) ComEd entered into various contracts for the procurement of renewable energy and RECs that expire between 2012 and 2032. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. If events were to occur such that ComEd is not allowed to recover the costs under these contracts from retail customers, ComEd may elect to reduce the annual quantity purchased under these contracts. See Note 4 - Regulatory Matters for additional information.

(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2012 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 Program. See Note 4 - Regulatory Matters for additional information.

(d) BGE entered into various contracts for the procurement of electricity that expire between 2012 and 2014. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 - 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) of which a portion relate to generating stations to be divested. See Note 3 - Mergers and Acquisitions for further details. PECO and BGE have commitments to purchase natural gas, related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of September 30, 2012, these net commitments were as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Generation	$	8,668	$	263	$	1,252	$	1,298	$	1,279	$	929	$	3,647
PECO		412		55		114		68		53		31		91
BGE		657		44		125		72		52		51		313

Other Purchase Obligations

The Registrants' other purchase obligations as of September 30, 2012, which primarily represent commitments for services, materials and information technology, are as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Exelon	$	1,049	$	434	$	217	$	135	$	94	$	32	$	137
Generation		555		248		110		91		69		8		29
ComEd		115		41		34		6		5		5		24
PECO		109		61		21		17		1		1		8
BGE		19		17		2		—		—		—		—

Construction Commitments

Generation has committed to the construction of a solar PV facility in Los Angeles County, California. Generation's estimated commitments are $192 million and $650 million for the years 2012 and 2013, respectively. See Note 3 – Merger and Acquisitions for additional information.

Generation has committed to the construction of approximately 400 MW of new wind facilities during 2012, approximately 272MW of which is still under construction as of September 30, 2012. Generation's estimated commitments for the wind turbines are approximately $100 million for the remainder of 2012, primarily related to the procurement of the turbines.

Refer to Note 4 - Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan and BGE's comprehensive smart grid initiative.

Constellation Merger Commitments

The tables above do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 3 - Merger and Acquisitions for additional information on the merger commitments.

Contingencies

Commercial Commitments

The Registrants' commercial commitments as of September 30, 2012, representing commitments potentially triggered by future events were as follows:

		Exelon			Generation			ComEd			PECO			BGE

Letters of credit (non-debt) (a)	$	2,290		$	2,082		$	142		$	22		$	1
Guarantees		10,406	(b)		2,355	(c)		208	(d)		181	(e)		250	(f)
Nuclear insurance premiums (g)		2,098			2,098			0			0			0

Total commercial commitments	$	14,794		$	6,535		$	350		$	203		$	251

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

(b) Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $1.5 billion at September 30, 2012, which represents the total amount Exelon could be required to fund based on September 30, 2012 market prices.

(c) Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $211 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.5 billion at September 30, 2012, which represents the total amount Generation could be required to fund based on September 30, 2012 market prices.

(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III.

(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV.

(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II.

(g) Does not include potential maximum combined retrospective premium obligations of CENG amounting to $691 million of which Generation's ownership interest is 50.01%.

Nuclear Insurance (Exelon and Generation)

The Price-Anderson Act requires mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in $12.2 billion in funds available for public liability claims for any single incident at any power reactor site that exceeds the primary level of financial protection currently required ($375 million). Additionally, Generation is also required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation is $2.1 billion which is included above in the Commercial Commitments table and which does not include the potential maximum combined retrospective premium obligations of CENG. See the Nuclear Insurance section within Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation's and BGE's 2011 Form 10-K for additional details on Generation's nuclear insurance premiums.

Indemnifications Related to 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).

In connection with the sale, Generation recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. 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 September 30, 2012 and is set to expire in 2014. The guarantee is included above in the Commercial Commitments table under 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 September 30, 2012. Generation 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 Guarantees.

Environmental Issues

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

ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, 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 sites require some level of remediation under the direction of the MDE. The required remediation cost at these two sites is not considered material. One additional 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. During the second and third quarter of 2012, ComEd and PECO, respectively, completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $146 million and $7 million, respectively. See Note 4 - Regulatory Matters for additional information regarding the associated regulatory assets.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time of each study and the remediation standards currently required by the 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 September 30, 2012 and December 31, 2011, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

September 30, 2012	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	351	$	307
Generation		35		0
ComEd		265		260
PECO		50		47
BGE		1		0
December 31, 2011	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	224	$	168
Generation		47		0
ComEd		127		121
PECO		50		47
BGE		0		0

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

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 C.P. Crane, Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, H.A. Wagner, 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. See Item 2. properties of the Exelon 2011 Form 10-K and ITEM 2. PROPERTIES of the Constellation 2011 Form 10-K for a description of these facilities.

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 rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another 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, the operator of Salem, 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 be approximately $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 Maryland Department of the Environment 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. Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 million to comply with the consent decree. As of September 30, 2012, approximately $18 million of these costs had been paid, resulting in a remaining liability at September 30, 2012 of $5 million.

Alleged Conemaugh Clean Streams Violation by PA DEP. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station (CGS), violated the Pennsylvania Clean Streams Law. GenOn has been engaged in discussions with PA DEP and has reached agreement on a proposed Consent Order that will be submitted for court approval following a public comment period. Under the proposed Consent Order, GenOn will be obligated to pay a civil penalty of $500,000, of which Generation's responsibility would be approximately $200,000.

Air

Cross State Air Pollution Rule. 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 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. On July 7, 2011, the U.S. EPA published the final rule, now 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. The final rule maintains the January 1, 2012 and January 1, 2014 phase-in dates that were in the proposed Transport Rule. However, the CSAPR imposes tighter emissions caps than the proposed Transport Rule and includes six additional states under the summertime NOx reduction requirements. These emissions limits may be further reduced as the U.S. EPA finalizes more restrictive ozone and particulate matter NAAQS in the 2012 - 2014 timeframe.

Under the CSAPR, Generation units will receive allowances based on historic heat input, intrastate, and limited interstate, trading of allowances is permitted, subject to certain limitations. The CSAPR restricts 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 are not expected to be used by Generation's fossil-fuel power plants and that have 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 September 30, 2012, Generation had $39 million of emission allowances carried at the lower of weighted average cost or market.

On October 6, 2011 and February 7, 2012, the U.S. EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to the CSAPR. On June 12, 2012, U.S. EPA issued its final technical corrections and associated updates to state emission budgets, and generating unit emission allowance allocations. On a related matter, on May 30, 2012, U.S. EPA issued its final rule with regard to electric generating unit regulation under the regional haze program. Under this final rule, states participating in the CSAPR trading programs will be allowed to use those programs in place of source-specific BART for sulfur dioxide and/or nitrogen oxide emissions from power plants that are subject to the regional haze rule

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. The D.C. Circuit Court granted permission for Exelon, as well as a number of other parties, to intervene in the litigation in support of the rule. 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 had exceeded its authority in certain material aspects of 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 October 5, 2012, the DOJ, on behalf of the U.S. EPA, filed a petition for a re-hearing en banc (i.e., before all the D.C. Circuit Court judges) of the panel's decision. On the same date Exelon joined with other industry members in a petition for an en banc review.

EPA Mercury and Air Toxics Standards (MATS). On April 16, 2012, the MATS rule to reduce emissions of toxic air pollutants from electric generating units (EGUs) became final. The MATS rule also finalized the new source performance standards for EGUs. The MATS rule resulted from a finding by the D.C. Circuit Court that the prior rule, known as the Clean Air Mercury Rule (CAMR), was invalid because it did not regulate mercury as a HAP. 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 some time in 2013.

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, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation – Brandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for the merger, Exelon agreed to divest these generating stations. It is anticipated that these plants are well positioned to comply with CSAPR and MATS, since Maryland has adopted SO2, NOx, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.

In addition, as of September 30, 2012, Exelon had a $678 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.

NAAQS. The U.S. EPA previously announced that it would complete a review of NAAQS in the 2011 - 2014 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide, ozone, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations. In July 2012, the D.C. Circuit Court issued separate rulings 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) 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 with an oral argument scheduled for November 2012. On June 14, 2012, the U.S. EPA proposed revisions to the Agency's particulate matter NAAQS and indicated that it would issue a final rule by December 14, 2012. In its proposed rule, the U.S. EPA has requested public comment on a lowered annual PM2.5 standard, as well as proposed a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its proposals that by 2020 it expects most areas of the country will be in attainment of the new 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.

Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received a NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several 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 1999.

The generating stations are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations 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 August 2009, the DOJ and the Illinois Attorney General filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon were 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 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 substantially similar to 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 U.S. District Court granted ComEd's motion to dismiss the May 2010 complaint. On January 3, 2012, upon leave of the U.S. District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals.

In connection with Exelon's 2001 corporate restructuring, Generation assumed ComEd's rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the amended complaint, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that, in light of the District Court decision the likelihood of loss is remote. Therefore, no reserve has been established. Further, Generation believes, that it would be reimbursed by Midwest Generation and EME for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME. On July 31, 2012, Edison International (EI), the parent company of EME, stated that EME may not have sufficient liquidity to repay unsecured debt due in June 2013. In addition, on November 1, 2012, EI stated that there is no assurance that interest payments due on the unsecured debt would be paid as required on November 15, 2012, and that failure to pay will likely result in EME's filing for protection under Chapter 11 of the U.S. Bankruptcy Code. In that event, ComEd and Generation would be unsecured creditors with respect to any indemnification obligations owed by EME and Midwest Generation.

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 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 PRPs to effectuate the remedy. An 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 the use of an 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 have agreed to toll the statute of limitations until August 2013 so that settlement discussions can 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 and the motions are still before the Court. Exelon remains potentially liable due to its indemnification responsibilities of Cotter described above. Due to the early stage of the litigation, Exelon is unable to determine the extent of its potential liability, 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 2012. 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 possible loss, if any, cannot be determined.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, 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 curiam 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 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 environmental groups, and some states to reply to the industry petitions.

On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO2 emissions to a thirty-year average of less than 1000 pounds per MWh (less than 1800 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.

Litigation and Regulatory Matters

Except to the extent noted below, the circumstances set forth in Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation's and BGE's 2011 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

Asbestos Personal Injury Claims (Exelon, Generation and BGE)

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

At September 30, 2012 and December 31, 2011, Generation had reserved approximately $64 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2012, approximately $14 million of this amount related to 170 open claims presented to Generation, while the remaining $50 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.

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 possible loss relating to these claims; as such, no accrual has been made. 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.

Gain on U.S. Department of Energy Settlements (Exelon and Generation)

CENG is currently in negotiations with the DOE 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 Nine Mile Point nuclear power plant. Any funds received from the DOE related to costs incurred prior to November 6, 2009 will belong to Generation. Generation has recorded a pre-acquisition contingent asset of approximately $16 million related to its share of the potential settlement. See Note 3 - Mergers and Acquisitions for additional information on the merger.

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 New York ISO 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 nine months ended September 30, 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 September 30, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 3 - 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 27, 2012, the ICC Staff and the Illinois Attorney General (AG) filed testimony in the ICC proceeding. They both disagreed with ComEd's interpretation that the statute does not apply to the interruptions caused by the 2011 storms. The ICC witness supported granting a waiver for three of the six storms, while the AG asserted that ComEd should be held responsible for the damages from all the storms.

A hearing in this proceeding was held on July 10-12, 2012. At the hearing, the ICC Staff witness, based on updated data provided by ComEd, now testified that ComEd should receive a waiver of liability in connection with five of the six storm systems in the Summer 2011 Storm Docket. As for the sixth storm system that struck on July 11, 2011 and affected more than 900,000 customers, the ICC Staff witness testified that 51,767 customers were affected by interruptions for which he felt a waiver should not be granted. Post-hearing briefing was concluded in September 2012. The Administrative Law Judge has not stated when he expects to issue a proposed Order.

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 February 14, 2012, the ICC Staff and the AG filed testimony in the proceeding. ICC staff recommended that the ICC issue ComEd a waiver based on the extreme weather conditions. The AG took the same position as it had in the Summer 2011 Storm Docket noted above. A hearing on this proceeding was also held on July 10-12, 2012 and post hearing briefing is also underway. Additional active proceedings related to storms of lesser collective impact are also pending.

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 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 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.

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 losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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

See Note 10 - Income Taxes for information regarding the Registrants' income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

The entire disclosure for commitments and contingencies.

Reference 1: 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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Supplemental Financial Information [Abstract]

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

9 Months Ended

Sep. 30, 2012

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

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

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants' Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012 and 2011:

Three Months Ended September 30, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds —
		Regulatory Agreement Units(a)	$	33	$	33	$	0	$	0	$	0
		Non-Regulatory Agreement Units(a)		10		10		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		202		202		0		0		0
		Non-Regulatory Agreement Units		71		71		0		0		0
	Net unrealized gains on pledged assets -
		Zion Station decommissioning		22		22		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(208)		(208)		0		0		0
Total decommissioning-related activities				130		130		0		0		0
Investment income				5		1		0		0		3
Long-term lease income				7		0		0		0		0
Interest income related to uncertain income tax positions				0		1		1		0		0
Credit facility termination fees				(43)		(43)		0		0		0
AFUDC - Equity				4		0		1		1		2
Other				(2)		(6)		3		1		0

Other, net			$	101	$	83	$	5	$	2	$	5


Nine Months Ended September 30, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds —
		Regulatory Agreement Units(a)	$	143	$	143	$	0	$	0	$	0
		Non-Regulatory Agreement Units(a)		77		77		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		352		352		0		0		0
		Non-Regulatory Agreement Units		101		101		0		0		0
	Net unrealized gains on pledged assets -
		Zion Station decommissioning		60		60		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(453)		(453)		0		0		0
Total decommissioning-related activities				280		280		0		0		0
Investment income				15		2		1		2		9
Long-term lease income				22		0		0		0		0
Interest income related to uncertain income tax positions				14		1		1		0		0
Credit facility termination fees				(85)		(85)		0		0		0
AFUDC - Equity				11		0		2		3		8
Other				(4)		(13)		8		1		1

Other, net			$	253	$	185	$	12	$	6	$	18

Three Months Ended September 30, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a)
		Regulatory Agreement Units	$	16	$	16	$	0	$	0	$	0
		Non-Regulatory Agreement Units		13		13		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory Agreement Units		(363)		(363)		0		0		0
		Non-Regulatory Agreement Units		(141)		(141)		0		0		0
	Net unrealized losses on pledged assets
		Zion Station decommissioning		(4)		(4)		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		281		281		0		0		0
Total decommissioning-related activities				(198)		(198)		0		0		0
Investment income				1		0		0		1		3
Long-term lease income				7		0		0		0		0
Interest income related to uncertain income tax positions				7		0		12		0		0
AFUDC - Equity				4		0		2		2		4
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				1		(2)		2		0		1

Other, net			$	(142)	$	(164)	$	16	$	3	$	8

Nine Months Ended September 30, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a)
		Regulatory Agreement Units	$	97	$	97	$	0	$	0	$	0
		Non-Regulatory Agreement Units		39		39		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory Agreement Units		(223)		(223)		0		0		0
		Non-Regulatory Agreement Units		(88)		(88)		0		0		0
	Net unrealized income on pledged assets
		Zion Station decommissioning		41		41		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		60		60		0		0		0
Total decommissioning-related activities				(74)		(74)		0		0		0
Investment income				3		0		0		3		10
Long-term lease income				21		0		0		0		0
Interest income related to uncertain income tax positions				53		33		13		1		0
AFUDC - Equity				14		0		6		8		11
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				1		(7)		5		(1)		1

Other, net			$	54	$	(12)	$	24	$	11	$	22

__________

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

(b) Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income taxes related to all NDT fund activity for those units. See Note 12 of the Exelon 2011 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants' Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011:


Nine Months Ended September 30, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,263	$	540	$	396	$	154	$	184
Regulatory assets		89		0		62		7		34
Amortization of intangible assets		24		24		0		0		0
Amortization of energy contract assets and liabilities (a)		731		811		0		0		0
Nuclear fuel (a)		628		629		0		0		0
Asset retirement obligation accretion (b)		174		174		0		0		0

Total depreciation, amortization, accretion and depletion	$	2,909	$	2,178	$	458	$	161	$	218

Nine Months Ended September 30, 2011	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	947	$	416	$	374	$	141	$	170
Regulatory assets		40		0		31		9		35
Nuclear fuel (a)		556		556		0		0		0
Asset retirement obligation accretion (b)		159		159		0		0		0

Total depreciation, amortization and accretion	$	1,702	$	1,131	$	405	$	150	$	205

__________

(a) Included in purchased power and fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income.

Nine Months Ended September 30, 2012		Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs		$	606	$	259	$	212	$	38		$	44
Provision for uncollectible accounts			120		14		38		46			28
Stock-based compensation costs			75		0		0		0			0
Other decommissioning-related activity (a)			(108)		(108)		0		0			0
Energy-related options (b)			119		119		0		0			0
Amortization of regulatory asset related to debt costs			13		0		10		2			1
Amortization of rate stabilization deferral			39		0		0		0			49
	Amortization of debt fair value adjustment		(49)		(23)		0		0			0
Discrete impacts from EIMA (c)			43		0		43		0			0
Merger-related commitments (d)			179		35		0		0			28
	Severance cost		120		34		0		1			0
Equity in losses of unconsolidated subsidiaries			69		69		0		0			0
Other			9		23		7		9			(3)

Total other non-cash operating activities		$	1,235	$	422	$	310	$	96		$	147

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs			20		0		21		(3)			21
Other regulatory assets and liabilities			(463)		0		(65)		7			(89)
Other current assets			52		(85)		(8)		(56)	(e)		(25)
Other noncurrent assets and liabilities			(40)		(110)		(72)		(5)			7

Total changes in other assets and liabilities		$	(431)	$	(195)	$	(124)	$	(57)		$	(86)

Non-cash investing and financing activities:
Merger with Constellation, common stock issued		$	7,365	$	5,258	$	0	$	0		$	0

	Total non-cash investing and financing activities:	$	7,365	$	5,258	$	0	$	0		$	0

Nine Months Ended September 30, 2011	Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	407	$	187	$	160	$	24		$	43
Provision for uncollectible accounts		97		0		49		48			31
Stock-based compensation costs		55		0		0		0			0
Other decommissioning-related activity (a)		62		62		0		0			0
Energy-related options (b)		102		102		0		0			0
Amortization of regulatory asset related to debt costs		16		0		14		2			1
Amortization of rate stabilization deferral		0		0		0		0			45
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 (f)		(32)		0		(32)		0			0
Bargain purchase gain related to Wolf Hollow Acquisition		(36)		(36)		0		0			0
Other		18		47		5		0			(6)

Total other non-cash operating activities	$	703	$	362	$	210	$	74		$	98

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		(9)		0		(20)		11			(25)
Other regulatory assets and liabilities		0		0		12		13			13
Other current assets		(166)		(46)		(13)		(59)	(e)		(92)
Other noncurrent assets and liabilities		83		(19)		50		7			(50)

Total changes in other assets and liabilities	$	(92)	$	(65)	$	29	$	(28)		$	(154)

_________

(a) Includes the elimination of NDT fund-related 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 12 of the Exelon 2011 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

(c) Includes the establishment of a regulatory asset, pursuant to EIMA, which represents the ICC's approved distribution formula and associated rulings as of September 30, 2012 and ComEd's best estimate of the probable increase in distribution rates to provide recovery of prudent and reasonable costs incurred for the twelve months ended December 31, 2011 and the nine months ended September 30, 2012. See Note 4 - Regulatory Matters for more information.

(d) See Note 3 - Mergers and Acquisitions for more information on merger-related commitments.

(e) Relates primarily to prepaid utility taxes.

(f) In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 4 - Regulatory Matters for more information.

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the nine months ended September 30, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $75 million, $45 million and $30 million, respectively, and reimbursements of $85 million, $55 million and $30 million, respectively, related to PECO's and BGE's DOE SGIG programs. For the nine months ended September 30, 2011, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $47 million, $29 million and $18 million, respectively, and reimbursements of $86 million, $45 million and $41 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 4 - Regulatory Matters for additional information regarding the DOE SGIG.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2012 and December 31, 2011.

September 30, 2012	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	11,890	(a)	$	5,910	(a)	$	2,906	$	2,765	$	2,579
Accounts receivable:
Allowance for uncollectible accounts		310			85			81		109		35

December 31, 2011	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	10,959	(b)	$	5,313	(b)	$	2,750	$	2,662	$	2,465
Accounts receivable:
Allowance for uncollectible accounts		199			29			78		92		38

___________

(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,161 million.

(b) Includes accumulated amortization of nuclear fuel in the reactor core of $1,784 million.

PECO Installment Plan Receivables (Exelon and PECO)

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $21 million as of September 30, 2012 and December 31, 2011. 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 of the Exelon 2011 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2012 of $18 million consists of $1 million, $4 million and $13 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 September 30, 2012 and December 31, 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 their 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 of the Exelon 2011 Form 10-K.

Accumulated Other Comprehensive Income (Loss)

The following tables provide information about accumulated OCI (loss) recorded (after tax) within the Consolidated Balance Sheets of the Registrants as of September 30, 2012 and December 31, 2011:

September 30, 2012	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	459	$	730	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(2,887)		0		0		0		0
Other comprehensive income—equity investment in CENG		23		23		0		0		0
Unrealized gain (loss) on marketable securities		0		(1)		0		1		0

Total accumulated other comprehensive income (loss)	$	(2,405)	$	752	$	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 (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2012

Segment Information [Abstract]

Segment Information (Exelon, Generation, ComEd and PECO)

18. 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 an aggregate of 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 Independent System Operator (ISO) / Regional Transmission Operator (RTO) and/or North American Electric Reliability Corporation (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 New York ISO, 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 Florida Reliability Coordinating Council (FRCC) and the remaining portions of the SERC Reliability Corporation (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 Southwest Power Pool (SPP), covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the Western Electric Coordinating Council (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 Alberta Electric Systems Operator (AESO), Ontario Independent Electricity System Operator (OIESO) and the Canadian portion of MISO.

Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these regional reportable segments. 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 internally generated energy 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 clean-coal assets held for sale; Brandon Shores, Wagner, and C.P. Crane, 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 three and nine months ended September 30, 2012 and 2011 is as follows:

Three Months Ended September 30, 2012 and 2011

		Generation(a)		ComEd		PECO		BGE		Other(b)		Intersegment Eliminations		Exelon
Total revenues(c):
	2012	$	4,017	$	1,484	$	806	$	720	$	336	$	(798)	$	6,565
	2011		2,821		1,784		946		0		206		(503)		5,254
Intersegment revenues(d):
	2012	$	459	$	0	$	1	$	4	$	334	$	(798)	$	0
	2011		304		1		2		0		203		(503)		7
Net income (loss):
	2012	$	87	$	90	$	123	$	0	$	(3)	$	0	$	297
	2011		386		112		105		0		(1)		0		602
Total assets:
	September 30, 2012	$	41,090	$	22,471	$	9,661	$	7,504	$	10,150	$	(12,523)	$	78,353
	December 31, 2011		27,433		22,638		9,156		0		6,162		(10,394)		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 three months ended September 30, 2012 include revenue from sales to PECO of $ 171 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $180 million in the Midwest region, net of $ (15) million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the three months ended September 30, 2011 intersegment revenues for Generation include revenue from sales to PECO of $137 million in the Mid-Atlantic region, and sales to ComEd of $159 million in the Midwest region.

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

(c) For the three months ended September 30, 2012 and 2011, utility taxes of $28 million and $7 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2012 and 2011, utility taxes of $67 million and $64 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2012 and 2011, utility taxes of $40 million and $50 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2012, utility taxes of $20 million are included in revenues and expenses for BGE.

(d) 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 2 of the Exelon 2011 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

Generation total revenues:
	2012						2011
	Revenues from external customers (a)		Intersegment revenues		Total Revenues		Revenues from external customers (a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	1,428	$	(11)	$	1,417	$	1,032	$	-	$	1,032
Midwest		1,193		7		1,200		1,385		-		1,385
New England		390		1		391		2		-		2
New York		183		2		185		0		-		0
ERCOT		532		1		533		307		-		307
Other Regions (b)		317		12		329		77		-		77
Total Revenues for Reportable Segments	$	4,043	$	12	$	4,055	$	2,803	$	-	$	2,803
Other (c)		(35)		(3)		(38)		18		-		18
Total Generation Consolidated Operating Revenues	$	4,008	$	9	$	4,017	$	2,821	$	-	$	2,821

(a) Includes all wholesale and retail electric 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.

(c) Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation's economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. 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
	RNF from external customers (a)		Intersegment RNF		Total RNF		RNF from external customers (a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	919	$	(11)	$	908	$	835	$	-	$	835
Midwest		723		7		730		852		-		852
New England		80		1		81		1		-		1
New York		11		2		13		0		-		0
ERCOT		158		0		158		103		-		103
Other Regions (b)		30		12		42		(4)		-		(4)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	1,921	$	11	$	1,932	$	1,787	$	-	$	1,787
Other (c)		(26)		(11)		(37)		(37)		-		(37)
Total Generation Revenues net of purchased power and fuel expense	$	1,895	$	0	$	1,895	$	1,750	$	-	$	1,750

Nine Months Ended September 30, 2012 and 2011

												Intersegment
		Generation (a)		ComEd		PECO		BGE(b)		Other(c)		Eliminations		Exelon
Total revenues(d):
	2012	$	10,509	$	4,154	$	2,396	$	1,388	$	1,049	$	(2,291)	$	17,205
	2011		7,919		4,694		2,942		0		579		(1,429)		14,705
Intersegment revenues(e):
	2012	$	1,233	$	2	$	3	$	7	$	1,050	$	(2,291)	$	4
	2011		856		2		4		0		576		(1,429)		9
Net income (loss):
	2012	$	419	$	219	$	300	$	(50)	$	(101)	$	0	$	787
	2011		1,325		295		314		0		(45)		0		1,889

__________

(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2012 include revenue from sales to PECO of $407 million and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $ (30) million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the nine months ended September 30, 2011 intersegment revenues for Generation include revenue from sales to PECO of $394 million in the Mid-Atlantic region, and sales to ComEd of $450 million in the Midwest region.

(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through September 30, 2012.

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

(d) For the nine months ended September 30, 2012 and 2011, utility taxes of $ 60 million and $ 20 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2012 and 2011, utility taxes of $182 million and $184 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2012 and 2011, utility taxes of $108 million and $140 million, respectively, are included in revenues and expenses for PECO. For the period of March 12, 2012 through September 30, 2012, utility taxes of $42 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 2 of the Exelon 2011 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

Generation total revenues:
	2012						2011
	Revenues from external customers (a)		Intersegment revenues		Total Revenues		Revenues from external customers (a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	3,832	$	(43)	$	3,789	$	3,102	$	-	$	3,102
Midwest		3,600		19		3,619		4,151		-		4,151
New England		776		36		812		8		-		8
New York		394		(22)		372		0		-		0
ERCOT		1,073		1		1,074		507		-		507
Other Regions (b)		611		40		651		169		-		169
Total Revenues for Reportable Segments	$	10,286	$	31	$	10,317	$	7,937	$	-	$	7,937
Other (c)		212		(20)		192		(18)		-		(18)
Total Generation Consolidated Operating Revenues	$	10,498	$	11	$	10,509	$	7,919	$	-	$	7,919

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

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

Generation total revenues net of purchased power and fuel expense:
	2012						2011
	RNF from external customers (a)		Intersegment RNF		Total RNF		RNF from external customers (a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,605	$	(44)	$	2,561	$	2,567	$	-	$	2,567
Midwest		2,291		19		2,310		2,704		-		2,704
New England		144		36		180		6		-		6
New York		82		(22)		60		0		-		0
ERCOT		311		1		312		94		-		94
Other Regions (b)		49		41		90		(10)		-		(10)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	5,482	$	31	$	5,513	$	5,361	$	-	$	5,361
Other (c)		9		(31)		(22)		(237)		-		(237)
Total Generation Revenues net of purchased power and fuel expense	$	5,491	$	0	$	5,491	$	5,124	$	-	$	5,124

(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.

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.

Reference 1: 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.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
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Subsequent Events Disclosure [Line Items]

Subsequent Events (Exelon, PECO and BGE)

9 Months Ended

Sep. 30, 2012

Schedule Of Subsequent Events Text Block

19. Subsequent Events (Exelon, PECO and BGE)

On October 29, 2012, a category 1 hurricane, Hurricane Sandy, interrupted electric service delivery to more than 850,000 customers and 325,000 customers in PECO's and BGE's service territories, respectively. Restoration efforts will include significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies. PECO and BGE estimate that restoration efforts will result in approximately $49 million to $55 million and $33 million to $37 million of incremental operating and maintenance expense, respectively, and $32 million to $36 million and $13 million to $14 million of incremental capital expenditures, respectively, for the fourth quarter.

Fair Value of Financial Assets and Liabilities (Policies)	9 Months Ended
	Sep. 30, 2012
Fair Value Assets Measured on Recurring Basis Valuation Techniques
Cash Equivalents Valuation Techniques Used to Determine Fair Value	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 Valuation Techniques Used to Determine Fair Value	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. See Note 11 — Nuclear Decommissioning for further discussion on the NDT fund investments. Direct lending funds are investments in managed funds which invest in private companies for long-term capital appreciation. The fair value of these securities is determined using either an enterprise value model or a bond valuation model. Investments in direct lending funds 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.
Rabbi Trust Investments Valuation Techniques Used to Determine Fair Value	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 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 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 Valuation Techniques Used to Determine Fair Value	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 8 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.
Deferred Compensation Obligations Valuation Techniques Used to Determine Fair Value	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.

Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2012

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

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities [Table Text Block]

		September 30, 2012
		Exelon		Generation		BGE
Current assets		$	398	$	348	$	49
Noncurrent assets			471		432		-
	Total assets	$	869	$	780	$	49

Current liabilities		$	269	$	193	$	75
Noncurrent liabilities			573		235		299
	Total liabilities	$	842	$	428	$	374

Variable Interest Entity, Not Primary Beneficiary, Aggregated Disclosure [Member]

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities [Table Text Block]

				Equity
		Energy		Method
		Contract		Investment
September 30, 2012		VIEs		VIEs		Total
Total assets (a)		$	280	$	342	$	622
Total liabilities (a)			217		95		312
Registrants' ownership interest (a)			0		98		98
Other ownership interests (a)			63		149		212
Registrants' maximum exposure to loss:
	Letters of credit		8		0		8
	Carrying amount of equity method investments		0		78		78
	Debt and payment guarantees		0		5		5

_________________

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.

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.

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Regulatory Matters Tables [Abstract]

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2012

Regulatory assets and liabilities

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits(a)	$	264	$	3,499	$	0	$	0	$	2		$	0	$	1	$	0
Deferred income taxes			13		1,346		5		62		0			1,220		8		64
AMI and smart meter programs			2		54		2		5		0			24		0		25
Under-recovered distribution service
	costs		0		119		0		119		0			0		0		0
Debt costs			14		71		11		65		3			6		2		9
Fair value of BGE long-term debt (b)			43		226		0		0		0			0		0		0
Fair value of BGE supply contract (c)			94		31		0		0		0			0		0		0
Severance			30		36		25		19		0			0		5		17
Asset retirement obligations			0		84		0		59		0			25		0		0
MGP remediation costs			65		227		58		190		6			35		1		2
RTO start-up costs			3		3		3		3		0			0		0		0
Under-recovered electric universal
	service fund costs		8		0		0		0		8			0		0		0
Financial swap with Generation			0		0		352		0		0			0		0		0
Renewable energy and associated
	RECs		17		53		17		53		0			0		0		0
Under-recovered energy and
	transmission costs		62		0		22		0		7	(d)		0		33		0
DSP Program costs			2		2		0		0		2			2		0		0
DSP II Program costs			0		2		0		0		0			2		0		0
Deferred storm costs			3		7		0		0		0			0		3		7
Electric generation-related
	regulatory asset		16		44		0		0		0			0		16		44
Rate stabilization deferral			65		244		0		0		0			0		65		244
Energy efficiency and demand
	response programs		55		117		0		0		0			0		55		117
Other			30		27		16		14		14			9		0		5

Total regulatory assets		$	786		6,192	$	511	$	589	$	42		$	1,323	$	189	$	534

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,383	$	0	$	2,021	$	0		$	362	$	0	$	0
Removal costs			94		1,397		73		1,185		0			0		21		212
Energy efficiency and demand
	response programs		82		33		37		0		45			33		0		0
Electric distribution tax repairs			18		138		0		0		18			138		0		0
Gas distribution tax repairs			5		49						5			49
Over-recovered distribution service
	costs		45		0		45		0		0			0		0		0
Over-recovered uncollectible
	accounts		10		0		10		0		0			0		0		0
Over-recovered energy and
	transmission costs		39		0		7		0		32	(e)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			1		0		0		0		1			0		0		0
Customer rate credit			1		0		0		0		0			0		1		0
Other			1		0		0		0		1			0		0		0

Total regulatory liabilities		$	299	$	4,000	$	172	$	3,206	$	105		$	582	$	22	$	212

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		7		64
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	(d)		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		3

Total regulatory assets		$	390	$	4,518	$	657	$	699	$	39		$	1,216	$	174	$	550

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	(e)		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

Total regulatory liabilities		$	197	$	3,627	$	137	$	3,042	$	60		$	585	$	18	$	200

As of September 30, 2012, pension and other postretirement benefit regulatory assets include a regulatory asset established at the date of the merger related to the recognition of BGE's share of the underfunded status of the defined benefit postretirement plan as a liability on Exelon's Consolidated Balance Sheets. The regulatory asset is being amortized in accordance with the authoritative guidance for pensions and postretirement benefits over a period of approximately 12 years. BGE is currently recovering these costs through base rates. BGE is not earning a return on the recovery of these costs in base rates.
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.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates.
Includes $5 million related to under-recovered electric transmission costs and $2 million related to under-recovered natural gas costs under the PGC as of September 30, 2012. The balance as of December 31, 2011 related to under-recovered electric transmission costs.
Relates to the over-recovered electric supply costs under the GSA as of September 30, 2012. Includes $5 million related to the over-recovered natural gas costs under the PGC and $25 million related to the over-recovered electric supply costs under the GSA as of December 31, 2011.

As of September 30, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	203	$	56	$	72	$	75
Allowance for uncollectible accounts (b)		(18)		(6)		(7)		(5)
Purchased receivables, net	$	185	$	50	$	65	$	70

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)

9 Months Ended

Sep. 30, 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		9,240		3,948
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		2,668		1,266
Total assets		23,201		14,469

Current liabilities		3,431		2,798
Unamortized energy contracts		1,722		1,512
Long-term debt, including current maturities		6,038		2,972
Noncontrolling interest		92		92
Deferred credits and other liabilities and preferred securities		4,553		1,837
Total liabilities, preferred securities and noncontrolling interest		15,836		9,211
Total purchase price	$	7,365	$	5,258

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		Remainder of 2012		2013		2014		2015		2016
Unamortized energy contracts, net (a)	1.5	$	1,496	$	(714)	$	782	$	267	$	396	$	76	$	18	$	(31)
Trade name	10.0		243		(14)		229		10		24		24		24		24
Retail relationships	12.4		214		(9)		205		8		19		19		19		19

Total, net		$	1,953	$	(737)	$	1,216	$	285	$	439	$	119	$	61	$	12

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

Schedule of Restructuring and Related Costs [Text Block]

Three Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd		PECO		BGE
Severance charges	$	8	$	4	$	1	$	1	$	1
Stock compensation		3		2		1		0		0
Total severance benefits	$	11	$	6	$	2	$	1	$	1

Nine Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	117	$	68	$	16	$	8	$	18
Stock compensation		6		4		1		0		0
Other charges		7		4		1		0		1
Total severance benefits	$	130	$	76	$	18	$	8	$	19

_________________

The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively.
ComEd established regulatory assets of $18 million, as of September 30, 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 September 30, 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]

Three Months Ended September 30, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at June 30, 2012	$	118	$	30	$	2	$	0	$	12
Severance charges (a)		7		4		0		0		0
Stock compensation		3		1		0		0		0
One-time termination benefits (b)		1		1		0		0		0
Other charges (c)		0		0		0		0		0
Payments		(9)		(2)		0		0		(1)
Balance at September 30, 2012	$	120	$	34	$	2	$	0	$	11

Nine Months Ended September 30, 2012
Severance liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2011	$	0	$	0	$	0	$	0	$	0
Severance charges (a)		114		31		2		0		11
Stock compensation		6		2		0		0		0
One-time termination benefits (b)		3		1		0		0		0
Other charges (c)		7		2		0		0		1
Payments		(10)		(2)		0		0		(1)
Balance at September 30, 2012	$	120	$	34	$	2	$	0	$	11

Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits.
One-time termination benefits began to be recognized 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
		Three Months Ended September 30,				Three Months Ended September 30,
		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	4,293	$	5,133	$	6,841	$	8,219
Net income attributable to Exelon		282		163		492		379

Basic Earnings Per Share		n.a.		n.a.	$	0.58	$	0.45
Diluted Earnings Per Share		n.a.		n.a.		0.57		0.44

	Generation				Exelon
		Nine Months Ended September 30,				Nine Months Ended September 30,
		2012		2011 (a)		2012		2011 (b)
Total Revenues	$	12,753	$	14,996	$	20,084	$	23,839
Net income attributable to Exelon		805		690		1,439		1,119

Basic Earnings Per Share		n.a.		n.a.	$	1.79	$	1.32
Diluted Earnings Per Share		n.a.		n.a.		1.79		1.31

_________________

The amounts above include non-recurring costs directly related to the merger of $69 million and $318 million for the three and nine months ended September 30, 2011, respectively.
The amounts above include non-recurring costs directly related to the merger of $74 million and $242 million for the three and nine months ended September 30, 2011, respectively.

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.

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.

Equity Method Investments and Joint Ventures Tables [Line Items]

Investment in Constellation Energy Nuclear Group, LLC (Tables)

9 Months Ended

Sep. 30, 2012

Schedule of total equity in earnings of investment in CENG

	Three Months			For the Period March 12,
	Ended September 30,			through September 30,
	2012		2012
Equity investment income	$	58	$	53
Amortization of basis difference in CENG		(57)		(131)
Total equity in earnings (losses) - CENG	$	1	$	(78)

Schedule of summarized income statement information for CENG


	Income/(Expense)		Income/(Expense)			Accounts
	Three Months		For the Period		Income	Receivable/
	Ended		March 12 through		Statement	(Accounts Payable)
Agreement	September 30, 2012		September 30, 2012		Classification	At September 30, 2012
PPA	$	(282)	$	(541)	Purchased power and fuel	$	(86)
PSAA		1		2	Operating revenues		-
SSA		14		30	Operating revenues		5

Equity Method Investments and Joint Ventures Tables [Line Items]

Schedule of total equity in earnings of investment in CENG

	Three Months			For the Period March 12,
	Ended September 30,			through September 30,
	2012		2012
Equity investment income	$	58	$	53
Amortization of basis difference in CENG		(57)		(131)
Total equity in earnings (losses) - CENG	$	1	$	(78)

Schedule of summarized income statement information for CENG


	Income/(Expense)		Income/(Expense)			Accounts
	Three Months		For the Period		Income	Receivable/
	Ended		March 12 through		Statement	(Accounts Payable)
Agreement	September 30, 2012		September 30, 2012		Classification	At September 30, 2012
PPA	$	(282)	$	(541)	Purchased power and fuel	$	(86)
PSAA		1		2	Operating revenues		-
SSA		14		30	Operating revenues		5

Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2012

Fair value of financial liabilities recorded at the carrying amount

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	289	$	4	$	285	$	0	$	737	$	737
Long-term debt (including amounts
	due within one year)		18,715		0		20,762		38		12,627		14,488
Long-term debt to financing trusts			649		0		650		0		390		358
SNF obligation			1,020		0		780		0		1,019		886
Preferred securities of subsidiary			87		0		83		0		87		79

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

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	1,117	$	0	$	0	$	1,117
Nuclear decommissioning trust fund investments
Cash equivalents		319		0		0		319
Equity
Equity securities		1,452		0		0		1,452
Commingled funds		0		1,906		0		1,906
Equity funds subtotal		1,452		1,906		0		3,358
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		1,100		0		0		1,100
Debt securities issued by states of the United States
and political subdivisions of the states		0		355		0		355
Debt securities issued by foreign governments		0		84		0		84
Corporate debt securities		0		1,734		0		1,734
Federal agency mortgage-backed securities		0		31		0		31
Commercial mortgage-backed securities (non-agency)		0		47		0		47
Residential mortgage-backed securities (non-agency)		0		15		0		15
Mutual funds		0		9		0		9
Fixed income subtotal		1,100		2,275		0		3,375
Direct lending securities		0		0		70		70
Other debt obligations		0		16		0		16
Nuclear decommissioning trust fund investments subtotal(b)		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		21		0		0		21
Commingled funds		0		20		0		20
Equity funds subtotal		21		20		0		41
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		78		15		0		93
Debt securities issued by states of the United States
and political subdivisions of the states		0		58		0		58
Corporate debt securities		0		260		0		260
Federal agency mortgage-backed securities		0		60		0		60
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Commingled funds		0		43		0		43
Fixed income subtotal		78		442		0		520
Direct lending securities		0		0		64		64
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal(c)		99		463		64		626

Rabbi trust investments
Cash equivalents		2		0		0		2
Mutual funds(d)(e)		69		0		0		69
Rabbi trust investments subtotal		71		0		0		71

Commodity mark-to-market derivative assets
Economic hedges		994		3,872		666		5,532
Proprietary trading		1,631		3,070		140		4,841
Effect of netting and allocation of collateral(f)		(2,597)		(5,695)		(238)		(8,530)
Commodity mark-to-market assets subtotal(g)		28		1,247		568		1,843
Interest rate mark-to-market derivative assets		0		125		0		125
Other investments		2		0		17		19

Total assets		4,188		6,032		719		10,939

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,225)		(2,814)		(351)		(4,390)
Proprietary trading		(1,678)		(2,881)		(222)		(4,781)
Effect of netting and allocation of collateral(f)		2,772		5,336		229		8,337
Commodity mark-to-market liabilities subtotal(g)(h)		(131)		(359)		(344)		(834)
Interest rate mark-to-market derivative liabilities		0		(95)		0		(95)
Deferred compensation		0		(101)		0		(101)

Total liabilities		(131)		(555)		(344)		(1,030)

Total net assets	$	4,057	$	5,477	$	375	$	9,909

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
Direct lending securities		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
Direct lending securities		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
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 September 30, 2012 and December 31, 2011, respectively.

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis

Three Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of June 30, 2012		$	54	$	59	$	295		$	17	$	425
Total realized / unrealized gains (losses)
	Included in net income		0		0		(97)	(a)		0		(97)
	Included in regulatory assets		2		0		41	(b)		0		43
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Change in collateral			0		-		(15)			0		(15)
Purchases, sales, issuances and settlements
	Purchases (c)		14		4		-			0		18

Balance as of September 30, 2012		$	70	$	64	$	224		$	17	$	375
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2012	$	0	$	0	$	(42)		$	0	$	(42)

Nine Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2011		$	13	$	37	$	17		$	0	$	67
Total realized / unrealized gains (losses)
	Included in net income		0		0		(157)	(a)		0		(157)
	Included in other comprehensive income		0		0		1			0		1
	Included in regulatory assets		2		0		36	(b)		0		38
Change in collateral			0		0		(7)			0		(7)
Purchases, sales, issuances and settlements
	Purchases (c)		55		36		329			17		437
	Sales		0		(9)		0			0		(9)
Transfers into Level 3			0		0		(34)			0		(34)
Transfers out of Level 3			0		0		39			0		39

Balance as of September 30, 2012		$	70	$	64	$	224		$	17	$	375
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012	$	0	$	0	$	(16)		$	0	$	(16)

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

Three Months Ended September 30, 2011			Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of June 30, 2011			$	0	$	34	$	(16)		$	18
Total realized / unrealized gains (losses)
	Included in income			0		0		(8)	(a)		(8)
	Included in other comprehensive income			0		0		(15)	(b)		(15)
	Included in regulatory assets			0		0		(18)			(18)
	Included in payable for Zion Station decommissioning			0		(3)		0			(3)
Change in collateral				0		0		8			8
Purchases, sales, issuances and settlements
	Purchases			6		17		0			23
	Sales			0		(10)		0			(10)
Transfers out of Level 3				0		0		24			24
Balance as of September 30, 2011			$	6	$	38	$	(25)		$	19
The amount of total gains included in income attributed to
	the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2011		$	0	$	0	$	(5)		$	-5

Nine Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Total
Balance as of December 31, 2010			$	0	$	0	$	50		$	50
Total realized / unrealized gains (losses)
	Included in other comprehensive income			0		0		(27)	(a)		(27)
	Included in regulatory assets			0		0		(51)	(b)		(51)
Change in collateral				0		0		15			15
Purchases, sales, issuances and settlements
	Purchases			6		60		4			70
	Sales			0		(22)		0			(22)
Transfers out of Level 3				0		0		(16)			(16)
Balance as of September 30, 2011			$	6	$	38	$	(25)		$	19
The amount of total gains included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2011		$	0	$	0	$	18		$	18

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 three months ended
	September 30, 2012	$	(106)	$	9
Total gains (losses) included in income for the nine months ended
	September 30, 2012	$	(195)	$	38
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended September 30, 2012	$	(48)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the nine months ended September 30, 2012	$	(45)	$	29

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended
	September 30, 2011	$	(5)	$	(3)
Total gains (losses) included in income for the nine months ended
	September 30, 2011	$	2	$	(2)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the three months ended September 30, 2011	$	1	$	(6)
Change in the unrealized gains (losses) relating to assets and liabilities held
	for the nine months ended September 30, 2011	$	22	$	(4)

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 September 30, 2012 (d)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	386	Discounted Cash Flow	Forward power price	$	8		-	$	76
			Discounted Cash Flow	Forward gas price	$	3.04		-	$	6.35
			Option Model	Volatility percentage		26	%	-		120	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	(83)	Discounted Cash Flow	Forward power price	$	13		-	$	108
			Option Model	Volatility percentage		22	%	-		67	%

Mark-to-market derivatives – Transactions with affiliates (Generation and ComEd) (b)	$	352	Discounted Cash Flow	Marketability reserve		7.3	%	-		8.7	%

Mark-to-market derivatives (ComEd)	$	(70)	Discounted Cash Flow	Forward heat rate (c)		8.5	%	-		9.5	%
				Marketability reserve		3.5	%	-		8.3	%
				Renewable factor		80	%	-		126	%

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 $352 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 below do not include cash collateral held on level three positions of $9 million as of September 30, 2012.

Fair value of financial liabilities recorded at the carrying amount

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	11	$	0	$	11	$	0	$	2	$	2
Long-term debt (including amounts
	due within one year)		7,383		0		7,839		20		3,677		4,231
SNF obligation			1,020		0		780		0		1,019		886

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

As of September 30, 2012	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents	$	518	$	0	$	0	$	518
Nuclear decommissioning trust fund investments
Cash equivalents		319		0		0		319
Equity
Equity securities		1,452		0		0		1,452
Commingled funds		0		1,906		0		1,906
Equity funds subtotal		1,452		1,906		0		3,358
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		1,100		0		0		1,100
Debt securities issued by states of the United States and
political subdivisions of the states		0		355		0		355
Debt securities issued by foreign governments		0		84		0		84
Corporate debt securities		0		1,734		0		1,734
Federal agency mortgage-backed securities		0		31		0		31
Commercial mortgage-backed securities (non-agency)		0		47		0		47
Residential mortgage-backed securities (non-agency)		0		15		0		15
Mutual funds		0		9		0		9
Fixed income subtotal		1,100		2,275		0		3,375
Direct lending securities		0		0		70		70
Other debt obligations		0		16		0		16
Nuclear decommissioning trust fund investments subtotal(b)		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		21		0		0		21
Commingled funds		0		20		0		20
Equity funds subtotal		21		20		0		41
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		78		15		0		93
Debt securities issued by states of the United States and
political subdivisions of the states		0		58		0		58
Corporate debt securities		0		260		0		260
Federal agency mortgage-backed securities		0		60		0		60
Commercial mortgage-backed securities (non-agency)		0		6		0		6
Commingled funds		0		43		0		43
Fixed income subtotal		78		442		0		520
Direct lending securities		0		0		64		64
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal(c)		99		463		64		626

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		994		3,872		1,018		5,884
Proprietary trading		1,631		3,070		140		4,841
Effect of netting and allocation of collateral(f)		(2,597)		(5,695)		(238)		(8,530)
Commodity mark-to-market assets subtotal(g)		28		1,247		920		2,195
Interest Rate mark-to-market derivative assets		0		111		0		111
Other investments		2		0		17		19

Total assets		3,532		6,018		1,071		10,621

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,225)		(2,814)		(281)		(4,320)
Proprietary trading		(1,678)		(2,881)		(222)		(4,781)
Effect of netting and allocation of collateral(f)		2,772		5,336		229		8,337
Commodity mark-to-market liabilities subtotal		(131)		(359)		(274)		(764)
Interest rate mark-to-market derivative liabilities		0		(95)		0		(95)
Deferred compensation		0		(27)		0		(27)

Total liabilities		(131)		(481)		(274)		(886)

Total net assets	$	3,401	$	5,537	$	797	$	9,735

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
Direct lending securities		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
Direct lending securities		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 September 30, 2012 and December 31, 2011, respectively.

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis

Three Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives				Other Investments	Total
Balance as of June 30, 2012		$	54	$	59	$	912			17	$	1,042
Total unrealized / realized gains (losses)
	Included in income		-		-		(112)	(a)		-		(112)
	Included in other comprehensive income		-		-		(139)	(b)		-		(139)
	Included in noncurrent payables to affiliates		2		-		-			-		2
	Included in payable for Zion Station decommissioning		-		1		-			-		1
Change in collateral			-		-		(15)			-		(15)
Purchases, sales, issuances and settlements
	Purchases (c)		14		4		-			-		18

Balance as of September 30, 2012		$	70	$	64	$	646		$	17	$	797
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2012	$	-	$	-	$	(77)		$	-	$	(77)

Nine Months Ended September 30, 2012		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives				Other Investments	Total
Balance as of December 31, 2011		$	13	$	37	$	817			-	$	867
Total unrealized / realized gains (losses)
	Included in income		-		-		(187)	(a)		-		(187)
	Included in other comprehensive income		-		-		(311)	(b)		-		(311)
	Included in noncurrent payables to affiliates		2		-		-			-		2
Change in collateral			-		-		(7)			-		(7)
Purchases, sales, issuances and settlements
	Purchases (c)		55		36		329			17		437
	Sales		-		(9)		-			-		(9)
Transfers into Level 3			-		-		(34)					(34)
Transfers out of Level 3			-		-		39			-		39

Balance as of September 30, 2012		$	70	$	64	$	646		$	17	$	797
The amount of total losses included in income
	attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012	$	-	$	-	$	(77)		$	-	$	(77)

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

Three Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of June 30, 2011		$	0	$	34	$	776		$	810
Total realized / unrealized gains (losses)
	Included in income		0		0		(8)	(a)		(8)
	Included in other comprehensive income		0		0		(110)	(b)		(110)
	Included in payable for Zion Station decommissioning		0		(3)		0			(3)
Changes in collateral			0		0		8			8
Purchases, sales, issuances and settlements
	Purchases		6		17		0			23
	Sales		0		(10)		0			(10)
Transfers out of Level 3 - Asset			0		0		24			24

Balance as of September 30, 2011		$	6	$	38	$	690		$	734

The amount of total gains included in income attributed to
	the change in unrealized (losses) related to assets and liabilities held for the three months ended September 30, 2011	$	0	$	0	$	(5)		$	(5)

Nine Months Ended September 30, 2011		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Total
Balance as of December 31, 2010		$	0	$	0	$	1,030		$	1,030
Total realized / unrealized gains (losses)
	Included in other comprehensive income		0		0		(343)	(b)		(343)
Changes in collateral			0		0		15			15
	Purchases		6		60		4			70
	Sales		0		(22)		0			(22)
Transfers out of Level 3 - Liability			0		0		(16)			(16)

Balance as of September 30, 2011		$	6	$	38	$	690		$	734

The amount of total gains included in income attributed to
	the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2011	$	0	$	0	$	18		$	18

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 three months ended September 30, 2012		$	(121)	$	9
Total gains (losses) included in income for the nine months ended
	September 30, 2012	$	(225)	$	38
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the three months ended September 30, 2012	$	(83)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the nine months ended September 30, 2012	$	(95)	$	18

		Operating Revenue		Purchased Power and Fuel
Total gains (losses) included in income for the three months ended
	September 30, 2011	$	(5)	$	(3)
Total gains (losses) included in income for the nine months ended September 30, 2011		$	2	$	(2)
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended September 30, 2011	$	1	$	(6)
Change in the unrealized gains (losses) relating to assets and liabilities held for
	the nine months ended September 30, 2011	$	22	$	(4)

Fair value of financial liabilities recorded at the carrying amount

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	35	$	0	$	35	$	0	$	0	$	0
Long-term debt (including amounts
	due within one year)		5,217		0		6,297		18		5,665		6,540
Long-term debt to financing trust			206		0		208		0		206		184

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

As of September 30, 2012		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds			9		0		0		9
	Rabbi trust investment subtotal		9		0		0		9

Total assets			9		0		0		9

Liabilities
Deferred compensation obligation			0		(9)		0		(9)
Mark-to-market derivative liabilities (b)(c)			0		0		(422)		(422)

Total liabilities			0		(9)		(422)		(431)

Total net assets (liabilities)		$	9	$	(9)	$	(422)	$	(422)

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.

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis

Three Months Ended September 30, 2012	Mark-to-Market Derivatives
Balance as of June 30, 2012	$	(617)
Total realized / unrealized gains included in regulatory assets (a)(b)		195
Balance as of September 30, 2012	$	(422)

Nine Months Ended September 30, 2012	Mark-to-Market Derivatives
Balance as of December 31, 2011	$	(800)
Total realized / unrealized gains included in regulatory assets (a)(b)		378
Balance as of September 30, 2012	$	(422)

Three Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of June 30, 2011	$	(788)
Total realized / unrealized gains included in regulatory assets (a)(b)		76
Balance as of September 30, 2011	$	(712)

Nine Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(971)
Total realized / unrealized gains included in regulatory assets (a)(b)		259
Balance as of September 30, 2011	$	(712)

Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis

Includes $7 million and $4 million of increases in fair value and $88 million and $309 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2011, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $19 million and $54 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2011, respectively.

Fair value of financial liabilities recorded at the carrying amount

		September 30, 2012								December 31, 2011
		Carrying		Fair Value						Carrying		Fair
		Amount			Level 1		Level 2		Level 3	Amount		Value
Short-term liabilities		$	225	$	0	$	225	$	0	$	225	$	225
Long-term debt (including amounts
	due within one year)		2,322		0		2,682		0		1,972		2,295
Long-term debt to financing trusts			184		0		180		0		184		174
Preferred securities			87		0		83		0		87		79

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

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	528	$	0	$	0	$	528
Rabbi trust investments - mutual funds(b)(c)		9		0		0		9

Total assets		537		0		0		537

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

Total liabilities		0		(18)		0		(18)

Total net assets (liabilities)	$	537	$	(18)	$	0	$	519

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 $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2012 and December 31, 2011, respectively.

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis

Three Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of June 30, 2011	$	(4)
Total realized gains included in regulatory assets		1
Balance as of September 30, 2011	$	(3)

Nine Months Ended September 30, 2011	Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(9)
Total realized gains included in regulatory assets		6	(a)
Balance as of September 30, 2011	$	(3)

Fair value of financial liabilities recorded at the carrying amount

		September 30, 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)		2,210		0	2,547	0		2,101		2,377
Long-term debt to financing trusts			258		0	264	0		258		256

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

As of September 30, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	52	$	0	$	0	$	52
Rabbi trust investments - mutual funds		5		0		0		5

Total assets		57		0		0		57

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

Total liabilities		0		(5)		0		(5)

Total net assets (liabilities)	$	57	$	(5)	$	0	$	52

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)

9 Months Ended

Sep. 30, 2012

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

		Gain (Loss) on Swaps				Gain (Loss) on Borrowings
		Nine Months Ended				Nine Months Ended
		September 30,				September 30,
Income Statement Classification		2012		2011		2012		2011
Interest expense (a)	$	(3)	$	1	$	(6)	$	(1)

Summary of the derivative fair value

		Generation								Other		Exelon
Description		Derivatives Designated as Hedging Instruments		Economic Hedges (a)		Proprietary Trading (a)		Subtotal		Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	-	$	3	$	19	$	22	$	-	$	22
Mark-to-market derivative assets (Noncurrent Assets)		42		10		37		89		14		103
Total mark-to-market derivative assets	$	42	$	13	$	56	$	111	$	14	$	125

Mark-to-market derivative liabilities (Current Liabilities)	$	(1)	$	(2)	$	(19)	$	(22)	$	0	$	(22)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(36)		0		(37)		(73)		0		(73)
Total mark-to-market derivative liabilities	$	(37)	$	(2)	$	(56)	$	(95)	$	0	$	(95)

Total mark-to-market derivative net assets (liabilities)	$	5	$	11	$	0	$	16	$	14	$	30

		Generation								ComEd		Other			Exelon
		Generation								ComEd		Other			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)	$	3,399	$	3,694	$	(6,187)	$	906	$	0		$	0	$	906
Mark-to-market
	derivative assets with affiliate (current assets)		352		0		0		352		0			(352)		0
Mark-to-market
	derivative assets (noncurrent assets)		2,133		1,147		(2,343)		937		0			0		937

Total mark-to-market
	derivative assets	$	5,884	$	4,841	$	(8,530)	$	2,195	$	0		$	(352)	$	1,843

Mark-to-market
	derivative liabilities (current liabilities)	$	(2,951)	$	(3,675)	$	6,144	$	(482)	$	(17)		$	0	$	(499)
Mark-to-market
	derivative liability with affiliate (current liabilities)		0		0		0		0		(352)			352		0
Mark-to-market
	derivative liabilities (noncurrent liabilities)		(1,369)		(1,106)		2,193		(282)		(53)			0		(335)

Total mark-to-market
	derivative liabilities	$	(4,320)	$	(4,781)	$	8,337	$	(764)	$	(422)		$	352	$	(834)

Total mark-to-market
	derivative net assets (liabilities)	$	1,564	$	60	$	(193)	$	1,431	$	(422)		$	0	$	1,009

__________

(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
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended September 30, 2012		Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30, 2012			$	923	(a)(c)	$	547
Reclassifications from accumulated OCI to net
	income	Operating Revenues		(171)	(b)		(88)	(d)
Ineffective portion recognized in income		Operating Revenues		0			0

Accumulated OCI derivative gain at September 30,
	2012		$	752	(a)(c)	$	459

(b) Includes $83 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(d) Includes $0 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax

		Generation			Exelon
Nine Months Ended September 30, 2012	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2011		$	925	(a)(c)	$	488
Effective portion of changes in fair value			432	(e)		301	(d)
Reclassifications from accumulated OCI to net income	Operating Revenues		(608)	(b)		(332)
Ineffective portion recognized in income	Operating Revenues		3			3

Accumulated OCI derivative gain at September 30, 2012		$	752	(a)(c)	$	459

__________

(a) Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011.

(b) Includes $276 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(d) Includes $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.

			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended September 30, 2011		Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30,
	2011		$	688	(a) (d)	$	209
Effective portion of changes in fair value				(26)	(b)		(26)
Reclassifications from accumulated OCI to net
	income	Operating Revenues		(98)	(c)		(45)
Ineffective portion recognized in income		Purchased Power		7			7
Accumulated OCI derivative gain at September 30, 2011			$	571	(a)(d)	$	145

(d) Excludes $6 million loss and $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2011 and June 30, 2011, respectively.

			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Total Cash Flow Hedge OCI Activity, Net of Income Tax
				Generation			Exelon
Nine Months Ended September 30, 2011		Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at
	December 31, 2010			$	1,011	(a) (d)	$	400
Effective portion of changes in fair value					(69)	(b)		(73)
Reclassifications from accumulated OCI to
	net income	Operating Revenues			(373)	(c)		(184)
Ineffective portion recognized in income		Purchased Power			2			2
Accumulated OCI derivative gain at September 30 2011				$	571	(a)(d)	$	145

__________

(d) Excludes $6 million loss and $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2011 and December 31, 2010.

Change in fair value and reclassification of derivative contracts

	Generation							Intercompany Eliminations	Exelon
				Purchased
	Operating			Power				Operating
Three Months Ended September 30, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(255)	$	129	$	(126)	$	35	$	(91)
Reclassification to realized at settlement		20		122		142		(19)		123
Net mark-to-market gains (losses)	$	(235)	$	251	$	16	$	16	$	32

	Generation							Intercompany Eliminations	Exelon
				Purchased
	Operating			Power				Operating
Nine Months Ended September 30, 2012	Revenues		and Fuel		Total			Revenues (a)	Total
Change in fair value	$	(85)	$	121	$	36	$	62	$	98
Reclassification to realized at settlement		(81)		326		245		(29)		216
Net mark-to-market gains (losses)	$	(166)	$	447	$	281	$	33	$	314

	Exelon and Generation
				Purchased
	Operating			Power
Three Months Ended September 30, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	22	$	22
Reclassification to realized at settlement		0		(101)		(101)
Net mark-to-market (losses) (b)	$	0	$	(79)	$	(79)

	Exelon and Generation
				Purchased
	Operating			Power
Nine Months Ended September 30, 2011 (As Reported)	Revenues		and Fuel		Total
Change in fair value	$	0	$	13	$	13
Reclassification to realized at settlement		0		(372)		(372)
Net mark-to-market (losses) (b)	$	0	$	(359)	$	(359)

	Exelon and Generation
				Purchased
	Operating			Power
Three Months Ended September 30, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	31	$	(9)	$	22
Reclassification to realized at settlement		(105)		4		(101)
Net mark-to-market (losses) (b)	$	(74)	$	(5)	$	(79)

	Exelon and Generation
				Purchased
	Operating			Power
Nine Months Ended September 30, 2011 (Pro Forma)	Revenues		and Fuel		Total
Change in fair value	$	44	$	(31)	$	13
Reclassification to realized at settlement		(374)		2		(372)
Net mark-to-market (losses) (b)	$	(330)	$	(29)	$	(359)

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.

		Three Months Ended				Nine Months Ended
	Location on Income	September 30,				September 30,
	Statement	2012		2011		2012		2011
Change in fair value	Operating Revenue	$	(2)	$	2	$	12	$	22
Reclassification to realized at
settlement	Operating Revenue		25		(6)		57		(19)

Net mark-to-market gains	Operating Revenue	$	23	$	(4)	$	69	$	3

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 September 30, 2012	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,968	$	492	$	1,476		0	$	0
Non-investment grade		46		25		21		0		0
No external ratings
Internally rated - investment grade		501		16		485		1		267
Internally rated - non-investment
grade		90		2		88		0		0
Total	$	2,605	$	535	$	2,070		1	$	267

Net Credit Exposure by Type of Counterparty	As of September 30, 2012

Investor-owned utilities, marketers and power producers		$	902
Energy cooperatives and municipalities			710
Financial institutions			386
Other			72
Total		$	2,070

Credit-Risk Related Contingent Feature		September 30, 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)


($2,720)	$2,156	($564)


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.

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.

Schedule Of Short Term Debt [Text Block]

Debt and Credit Agreements Year-End (Tables)

9 Months Ended

Sep. 30, 2012

Debt Tables [Line Items]

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolvers	$	2.0	December 2012 and August 2017	Letters of credit and cash
Generation
	Syndicated Revolver		5.3	August 2017	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2017	Letters of credit and cash
PECO
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
BGE
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
	Total	$	9.8

Excludes $118 million of credit facility agreements arranged with minority and community banks at Generation, ComEd and PECO. These facilities, which expired and were replaced in October 2012, were solely utilized to issue letters of credit.

Schedule Of Short Term Borrowing Activity [Text Block]

Debt and Credit Agreements Quarter-End (Tables)

9 Months Ended

Sep. 30, 2012

Debt Tables [Abstract]

Commercial paper and credit facility borrowings outstanding

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolvers	$	2.0	December 2012 and August 2017	Letters of credit and cash
Generation
	Syndicated Revolver		5.3	August 2017	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2017	Letters of credit and cash
PECO
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
BGE
	Syndicated Revolver		0.6	August 2017	Letters of credit and cash
	Total	$	9.8

Excludes $118 million of credit facility agreements arranged with minority and community banks at Generation, ComEd and PECO. These facilities, which expired and were replaced in October 2012, were solely utilized to issue letters of credit.

Issuance of Long-Term Debt

Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Senior Notes	4.250	%	June 15, 2022	$	523	Used for general corporate purposes and issued in connection with the Exchange Offer
Generation	Senior Notes	5.600	%	June 15, 2042	$	788	Used for general corporate purposes and issued in connection with the Exchange Offer
Generation	CEU Credit Agreement	1.990	%	June 16, 2016	$	43	Used to fund Upstream gas activities
Generation	DOE Project Financing	2.330 - 3.092	%	January 5, 2037	$	100	Funding for Antelope Valley solar development
Generation	Clean Horizons	2.500	%	June 7, 2030	$	38	Funding for Maryland solar development
BGE	Notes	2.800	%	August 15, 2022	$	250	Used to repay total outstanding commercial paper and for general corporate purposes
PECO	First and Refunding Mortgage Bonds	2.375	%	September 15, 2022	$	350	Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes

Company	Type	Interest Rate	Maturity		Amount	Use of Proceeds
ComEd	First Mortgage Bonds	1.625%	January 15, 2014	$	600	Used as an interim source of liquidity for January 2011 contribution for Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes.
ComEd	First Mortgage Bonds (a)	1.950%	September 1, 2016	$	250	To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011.
ComEd	First Mortgage Bonds (a)	3.400%	September 1, 2021	$	350	To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011.

Retirement of Long-Term Debt

Company	Type	Interest Rate		Maturity	Amount
ComEd	First Mortgage Bond Series 98	6.15	%	March 15, 2012		$	450
BGE	Rate Stabilization Bonds	5.68	%	April 1, 2017		$	31
BGE	Medium Term Notes	6.73 - 6.75	%	June 15, 2012		$	110
Generation	Armstrong Co. tax-exempt	5.00	%	December 1, 2042		$	46
Generation	CEU Credit Agreement	2.27	%	June 16, 2016		$	3
Generation	MEDCO Tax-Exempt Bonds	Variable		April 1, 2024		$	75
Generation	Solar Revolver	2.49	%	July 7, 2014		$	13
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
Exelon	Senior Notes	7.60	%	April 1, 2032		$	442
Exelon	Medium Term Notes	7.30	%	June 1, 2012		$	2

Company	Type	Interest Rate		Maturity	Amount
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
ComEd	Sinking fund debentures	4.75	%	December 1, 2011			1

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2012

Income Taxes Tables [Abstract]

Effective Income Tax Rate Reconciliation

For the Three Months Ended September 30, 2012		Exelon (a)		Generation (a)		ComEd		PECO		BGE (b)

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	0.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	5.6		5.9		5.0		3.0		0.0
	Qualified nuclear decommissioning trust fund income	7.8		21.5		0.0		0.0		0.0
	Domestic production activities deduction	0.3		0.8		0.0		0.0		0.0
	Tax exempt income	(0.2)		(0.5)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		0.6		0.0		0.0
	Amortization of investment tax credit, net deferred taxes	(4.8)		(13.0)		(0.5)		(0.3)		0.0
	Plant basis differences	(4.7)		0.0		(0.5)		(21.0)		0.0
	Production tax credits	(2.5)		(7.4)		0.0		0.0		0.0
	Fines & penalties	(0.1)		0.0		0.0		0.0		0.0
	Other (d)	(1.2)		7.1		0.0		0.2		0.0

Effective income tax rate		35.2	%	49.4	%	39.6	%	16.9	%	0.0	%

For the Nine Months Ended September 30, 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	(4.7)		2.5		5.4		3.2		2.3
	Qualified nuclear decommissioning trust fund income	6.9		10.9		0.0		0.0		0.0
	Tax exempt income	(0.3)		(0.5)		0.0		0.0		0.0
	Health Care Reform Legislation	0.2		0.0		0.6		0.0		(4.6)
	Amortization of investment tax credit, net deferred taxes	(2.3)		(3.3)		(0.5)		(0.3)		2.9
	Plant basis differences	(2.2)		0.0		(0.2)		(9.7)		7.2
	Production tax credits	(2.6)		(4.3)		0.0		0.0		0.0
	Fines & penalties	3.8		6.0		0.0		0.0		0.0
	Merger expenses (c)	3.6		0.0		0.0		0.0		(14.0)
	Other	(1.3)		0.8		0.2		(0.0)		4.5

Effective income tax rate		36.1	%	47.1	%	40.5	%	28.2	%	33.3	%


For the Three Months Ended September 30, 2011		Exelon		Generation		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	4.8		5.5		0.8		2.9		6.2
	Qualified nuclear decommissioning trust fund income	(6.4)		(10.2)		0.0		0.0		0.0
	Domestic production activities deduction	1.0		1.7		0.0		0.0		0.0
	Tax exempt income	(0.1)		(0.2)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		0.3		0.0		(16.4)
	Amortization of investment tax credit	(0.3)		(0.2)		(0.5)		(0.3)		13.8
	Plant basis differences	(3.2)		0.0		(0.7)		(23.8)		48.4
	Production tax credits	(1.1)		(1.7)		0.0		0.0		0.0
	Interest and penalties on unrecognized tax benefits (e)	0.0		0.0		0.0		0.0		137.8
	Other	0.1		0.3		0.4		0.1		75.2

Effective income tax rate		29.8	%	30.2	%	35.3	%	13.9	%	300.0	%

For the Nine Months Ended September 30, 2011		Exelon		Generation		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	4.1		4.9		3.4		(0.4)		4.8
	Qualified nuclear decommissioning trust fund income	(0.6)		(0.8)		0.0		0.0		0.0
	Domestic production activities deduction	(0.4)		(0.6)		0.0		0.0		0.0
	Tax exempt income	(0.1)		(0.2)		0.0		0.0		0.0
	Health Care Reform Legislation	0.0		0.0		(1.5)		0.0		(0.8)
	Amortization of investment tax credit	(0.3)		(0.2)		(0.4)		(0.3)		(0.5)
	Plant basis differences	(1.0)		0.0		(0.4)		(6.8)		(1.6)
	Production tax credits	(1.0)		(1.4)		0.0		0.0		0.0
	Interest and penalties on unrecognized tax benefits (e)	0.0		0.0		0.0		0.0		(1.1)
	Other	(0.3)		(0.9)		0.3		0.0		(0.1)

Effective income tax rate		35.4	%	35.8	%	36.4	%	27.5	%	35.7	%

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligations Tables [Abstract]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

Nuclear Decommissioning (Tables)

9 Months Ended

Sep. 30, 2012

Schedule Of Nuclear Decommissioning [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

Schedule Of Nuclear Decommissioning [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2011 (a)	$	3,680
Accretion expense		169
Net increase due to changes in estimated cash flows		749
Costs incurred to decommission retired plants		(2)
Nuclear decommissioning ARO at September 30, 2012 (a)	$	4,596

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units (a)	$	202	$	(363)	$	352	$	(223)
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units (b)(c)		71		(141)		101		(88)

Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2012

Retirement Benefits Tables [Abstract]

Schedule of Defined Benefit Plans Disclosures [Text Block]

			Pension Benefits				Other Postretirement Benefits
			Three Months Ended				Three Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Service cost		$	76	$	53	$	38	$	36
Interest cost			181		162		53		52
Expected return on assets			(258)		(235)		(28)		(27)
Amortization of:
	Transition obligation		0		0		2		2
	Prior service cost (benefit)		5		4		(3)		(10)
	Actuarial loss		117		83		19		16
Settlement Charges			9		0		0		0
Curtailment gain			0		0		(5)		0

Net periodic benefit cost		$	130	$	67	$	76	$	69

			Pension Benefits				Other Postretirement Benefits
			Nine Months Ended				Nine Months Ended
			September 30,				September 30,
			2012		2011		2012		2011
Service cost		$	211	$	159	$	114	$	107
Interest cost			524		487		157		155
Expected return on assets			(742)		(704)		(86)		(83)
Amortization of:
	Transition obligation		0		0		8		7
	Prior service cost (benefit)		12		11		(10)		(29)
	Actuarial loss		338		248		58		49
Settlement Charges			9		0		0		0
Contractual termination benefit cost (a)			14		0		6		0
Curtailment gain			0		0		(7)		0

Net periodic benefit cost		$	366	$	201	$	240	$	206

(a) As discussed above, ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge.

Schedule Of Pension And Other Postretirement Benefit Costs [Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Pension and Postretirement Benefit Costs	2012		2011		2012		2011
Generation	$	85	$	64	$	259	$	187
ComEd		75		53		212		160
PECO		12		8		38		24
BGE (a)(b)		14		15		46		43
BSC (c)		20		11		63		36

BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's pension and postretirement benefit costs for the three months and nine months ended September 30, 2011 were $15 million and $43 million, respectively. These amounts are not included in Exelon's net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above.

Schedule Of Defined Contributions [Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Savings Plan Matching Contributions	2012		2011		2012		2011
Exelon	$	16	$	26	$	49	$	64
Generation		7		13		23		33
ComEd		5		8		14		18
PECO		2		3		5		7
BGE (a)		1		1		5		5
BSC (b)		1		2		3		6

BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012.
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 7, 16, 20, 21
-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 Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=6930749&loc=d3e4179-114921

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2410-114920

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2439-114920

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2417-114920

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-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.

Corporate Restructuring And Plant Retirements Tables [Abstract]

Plant Retirements (Tables)

9 Months Ended

Sep. 30, 2012

Total severance benefits costs, recorded as operating and maintenance expense

Three Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd		PECO		BGE
Severance charges	$	8	$	4	$	1	$	1	$	1
Stock compensation		3		2		1		0		0
Total severance benefits	$	11	$	6	$	2	$	1	$	1

Nine Months Ended September 30, 2012
Severance Benefits (a)		Exelon		Generation		ComEd (b)		PECO		BGE (c)
Severance charges	$	117	$	68	$	16	$	8	$	18
Stock compensation		6		4		1		0		0
Other charges		7		4		1		0		1
Total severance benefits	$	130	$	76	$	18	$	8	$	19

_________________

The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively.
ComEd established regulatory assets of $18 million, as of September 30, 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 September 30, 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 corporate restructuring (excluding obligations recorded in equity)

Severance Benefits Obligation		Exelon and Generation
Balance at December 31, 2011	$	7
Cash payments		(2)

Balance at September 30, 2012	$	5

Stock-Based Compensation Plans (Tables)

9 Months Ended

Sep. 30, 2012

Common Stock Disclosure Tables [Abstract]

Stock Based Compensation Components [Text Block]

		Three Months Ended				Nine Months Ended
		September 30,				September 30,

Components of Stock-Based Compensation Expense		2012		2011		2012		2011

Performance share awards		$	5	$	6	$	32	$	17
Stock options			2		1		13		7
Restricted stock units			12		5		41		26
Other stock-based awards			1		1		3		3

Total stock-based compensation expense included in
	operating and maintenance expense		20		13		89		53

Income tax benefit			(8)		(5)		(34)		(21)

Total after-tax stock-based compensation expense		$	12	$	8	$	55	$	32

Stock Based Compensation Expense Subsidiaries [Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

Subsidiaries	2012		2011		2012		2011

Generation	$	9	$	6	$	33	$	24
ComEd		2		1		9		4
PECO		1		1		4		4
BGE (a)		1		0		4		0
BSC (b)		7		5		39		21

Total	$	20	$	13	$	89	$	53

(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.

Weighted Average Assumptions And Grand Date Fair Value Of Stock Options [Text Block]

	Three Months Ended						Nine Months Ended
	September 30,						September 30,

	2012			2011			2012			2011

Dividend yield		5.28	%		4.84	%		5.28	%		4.84	%
Expected volatility		23.20	%		24.40	%		23.20	%		24.40	%
Risk-free interest rate		1.30	%		2.65	%		1.30	%		2.65	%
Expected life (years)		6.25			6.25			6.25			6.25

Stock Option Activity [Text Block]

		Weighted Average
		Exercise Price
	Shares	(per share)

Balance of shares outstanding at December 31, 2011	11,553,761	$	48.49
Granted	2,372,000		39.66
Converted Constellation options	11,194,151		41.35
Exercised	(1,575,275)		26.57
Forfeited	(28,142)		44.88
Expired	(488,434)		48.59

Balance of shares outstanding at September 30, 2012	23,028,061	$	45.61

Exercisable at September 30, 2012 (a)	20,962,469	$	46.08

(a) Includes stock options issued to retirement eligible employees.

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)	(11,889,175)		41.39
Forfeited	(488,434)		48.59

Nonvested at September 30, 2012 (a)	2,065,592	$	40.60

(a) Excludes 2,719,671 and 1,348,000 of stock options issued to retirement-eligible employees as of September 30, 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 1,667,000 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	1,283,292		39.93
Converted Constellation restricted stock	825,735		38.91
Vested	(427,499)		47.69
Forfeited	(47,415)		42.67
Undistributed vested awards (b)	(602,276)		40.53

Nonvested at September 30, 2012 (a)	2,106,321	$	42.27

(a) Excludes 656,228 and 448,827 of restricted stock units issued to retirement-eligible employees as of September 30, 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	1,249,932		39.73
Vested	(159,194)		47.66
Forfeited	(113,761)		39.79
Undistributed vested awards (b)	(128,370)		40.98

Nonvested at September 30, 2012 (a)	1,195,455	$	40.17

(a) Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of September 30, 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.

Earnings Per Share and Equity (Tables)

9 Months Ended

Sep. 30, 2012

Earnings Per Share and Equity Tables [Abstract]

Reconciliation of basic and diluted earnings per share

			Three Months Ended September 30,				Nine Months Ended September 30,
			2012		2011		2012		2011

Net income on common stock		$	296	$	601	$	782	$	1,889

Average common shares outstanding — basic			854		663		804		663
Assumed exercise of stock options, performance share awards
	and restricted stock		3		2		2		1

Average common shares outstanding — diluted			857		665		806		664

Tabular disclosure of the effect of income (loss) on an entity's diluted earnings per share.

Commitments And Contingencies Tables Disclosure [Line Items]

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2012

Energy Commitments [Text Block]

	Net Capacity			Power-Related			Transmission Rights			Purchased Energy
	Purchases (a)			Purchases (b)			Purchases (c)			from CENG			Total

2012		$	111		$	8		$	8		$	148		$	275
2013			375			92			32			699			1,198
2014			352			62			26			451			891
2015			350			23			13			—			386
2016			266			9			2			—			277
Thereafter			672			8			36			—			716

Total		$	2,126		$	202		$	117		$	1,298		$	3,743

(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.

Utility Energy Purchase Commitments [Text Block]

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

ComEd
Electric supply procurement (a)	$	1,103	$	-	$	367	$	323	$	136	$	137	$	140
Renewable energy and RECs (b)		1,694		33		71		73		74		76		1,367
PECO
Electric supply procurement (c)		789		210		413		130		36		-		-
AECs		35		3		11		9		2		2		8
Curtailment services		4		4		-		-		-		-		-
BGE
Electric supply procurement (d)		1,171		201		707		263		-		-		-
Curtailment services		165		11		49		47		41		17		-

Fuel Purchase Commitments [Text Block]

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Generation	$	8,668	$	263	$	1,252	$	1,298	$	1,279	$	929	$	3,647
PECO		412		55		114		68		53		31		91
BGE		657		44		125		72		52		51		313

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Exelon	$	1,049	$	434	$	217	$	135	$	94	$	32	$	137
Generation		555		248		110		91		69		8		29
ComEd		115		41		34		6		5		5		24
PECO		109		61		21		17		1		1		8
BGE		19		17		2		—		—		—		—

Commercial Commitments [Text Block]

		Exelon			Generation			ComEd			PECO			BGE

Letters of credit (non-debt) (a)	$	2,290		$	2,082		$	142		$	22		$	1
Guarantees		10,406	(b)		2,355	(c)		208	(d)		181	(e)		250	(f)
Nuclear insurance premiums (g)		2,098			2,098			0			0			0

Total commercial commitments	$	14,794		$	6,535		$	350		$	203		$	251

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

(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III.

(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV.

(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II.

(g) Does not include potential maximum combined retrospective premium obligations of CENG amounting to $691 million of which Generation's ownership interest is 50.01%.

Accrued environmental liabilities [Text Block]

September 30, 2012	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	351	$	307
Generation		35		0
ComEd		265		260
PECO		50		47
BGE		1		0
December 31, 2011	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	224	$	168
Generation		47		0
ComEd		127		121
PECO		50		47
BGE		0		0

The entire disclosure for environmental loss contingencies, such as presence of hazardous waste, relevant information from reports issued by regulators, and estimated costs to achieve compliance with regulatory requirements. This element may be used for all of an entity's disclosures about environmental loss contingencies.

Supplemental Financial Information Tables [Line Items]

Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2012

Components of non-operating income and expenses

Three Months Ended September 30, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds —
		Regulatory Agreement Units(a)	$	33	$	33	$	0	$	0	$	0
		Non-Regulatory Agreement Units(a)		10		10		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		202		202		0		0		0
		Non-Regulatory Agreement Units		71		71		0		0		0
	Net unrealized gains on pledged assets -
		Zion Station decommissioning		22		22		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(208)		(208)		0		0		0
Total decommissioning-related activities				130		130		0		0		0
Investment income				5		1		0		0		3
Long-term lease income				7		0		0		0		0
Interest income related to uncertain income tax positions				0		1		1		0		0
Credit facility termination fees				(43)		(43)		0		0		0
AFUDC - Equity				4		0		1		1		2
Other				(2)		(6)		3		1		0

Other, net			$	101	$	83	$	5	$	2	$	5


Nine Months Ended September 30, 2012			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds —
		Regulatory Agreement Units(a)	$	143	$	143	$	0	$	0	$	0
		Non-Regulatory Agreement Units(a)		77		77		0		0		0
	Net unrealized gains on decommissioning trust funds —
		Regulatory Agreement Units		352		352		0		0		0
		Non-Regulatory Agreement Units		101		101		0		0		0
	Net unrealized gains on pledged assets -
		Zion Station decommissioning		60		60		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		(453)		(453)		0		0		0
Total decommissioning-related activities				280		280		0		0		0
Investment income				15		2		1		2		9
Long-term lease income				22		0		0		0		0
Interest income related to uncertain income tax positions				14		1		1		0		0
Credit facility termination fees				(85)		(85)		0		0		0
AFUDC - Equity				11		0		2		3		8
Other				(4)		(13)		8		1		1

Other, net			$	253	$	185	$	12	$	6	$	18

Three Months Ended September 30, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a)
		Regulatory Agreement Units	$	16	$	16	$	0	$	0	$	0
		Non-Regulatory Agreement Units		13		13		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory Agreement Units		(363)		(363)		0		0		0
		Non-Regulatory Agreement Units		(141)		(141)		0		0		0
	Net unrealized losses on pledged assets
		Zion Station decommissioning		(4)		(4)		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		281		281		0		0		0
Total decommissioning-related activities				(198)		(198)		0		0		0
Investment income				1		0		0		1		3
Long-term lease income				7		0		0		0		0
Interest income related to uncertain income tax positions				7		0		12		0		0
AFUDC - Equity				4		0		2		2		4
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				1		(2)		2		0		1

Other, net			$	(142)	$	(164)	$	16	$	3	$	8

Nine Months Ended September 30, 2011			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds (a)
		Regulatory Agreement Units	$	97	$	97	$	0	$	0	$	0
		Non-Regulatory Agreement Units		39		39		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory Agreement Units		(223)		(223)		0		0		0
		Non-Regulatory Agreement Units		(88)		(88)		0		0		0
	Net unrealized income on pledged assets
		Zion Station decommissioning		41		41		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities(b)		60		60		0		0		0
Total decommissioning-related activities				(74)		(74)		0		0		0
Investment income				3		0		0		3		10
Long-term lease income				21		0		0		0		0
Interest income related to uncertain income tax positions				53		33		13		1		0
AFUDC - Equity				14		0		6		8		11
Bargain purchase gain related to Wolf Hollow acquisition				36		36		0		0		0
Other				1		(7)		5		(1)		1

Other, net			$	54	$	(12)	$	24	$	11	$	22

__________

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

Components of depreciation, amortization and accretion, and other, net


Nine Months Ended September 30, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,263	$	540	$	396	$	154	$	184
Regulatory assets		89		0		62		7		34
Amortization of intangible assets		24		24		0		0		0
Amortization of energy contract assets and liabilities (a)		731		811		0		0		0
Nuclear fuel (a)		628		629		0		0		0
Asset retirement obligation accretion (b)		174		174		0		0		0

Total depreciation, amortization, accretion and depletion	$	2,909	$	2,178	$	458	$	161	$	218

Nine Months Ended September 30, 2011	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	947	$	416	$	374	$	141	$	170
Regulatory assets		40		0		31		9		35
Nuclear fuel (a)		556		556		0		0		0
Asset retirement obligation accretion (b)		159		159		0		0		0

Total depreciation, amortization and accretion	$	1,702	$	1,131	$	405	$	150	$	205

__________

(a) Included in purchased power and fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income.

Cash Flow Supplemental Disclosures

Nine Months Ended September 30, 2012		Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs		$	606	$	259	$	212	$	38		$	44
Provision for uncollectible accounts			120		14		38		46			28
Stock-based compensation costs			75		0		0		0			0
Other decommissioning-related activity (a)			(108)		(108)		0		0			0
Energy-related options (b)			119		119		0		0			0
Amortization of regulatory asset related to debt costs			13		0		10		2			1
Amortization of rate stabilization deferral			39		0		0		0			49
	Amortization of debt fair value adjustment		(49)		(23)		0		0			0
Discrete impacts from EIMA (c)			43		0		43		0			0
Merger-related commitments (d)			179		35		0		0			28
	Severance cost		120		34		0		1			0
Equity in losses of unconsolidated subsidiaries			69		69		0		0			0
Other			9		23		7		9			(3)

Total other non-cash operating activities		$	1,235	$	422	$	310	$	96		$	147

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs			20		0		21		(3)			21
Other regulatory assets and liabilities			(463)		0		(65)		7			(89)
Other current assets			52		(85)		(8)		(56)	(e)		(25)
Other noncurrent assets and liabilities			(40)		(110)		(72)		(5)			7

Total changes in other assets and liabilities		$	(431)	$	(195)	$	(124)	$	(57)		$	(86)

Non-cash investing and financing activities:
Merger with Constellation, common stock issued		$	7,365	$	5,258	$	0	$	0		$	0

	Total non-cash investing and financing activities:	$	7,365	$	5,258	$	0	$	0		$	0

Nine Months Ended September 30, 2011	Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	407	$	187	$	160	$	24		$	43
Provision for uncollectible accounts		97		0		49		48			31
Stock-based compensation costs		55		0		0		0			0
Other decommissioning-related activity (a)		62		62		0		0			0
Energy-related options (b)		102		102		0		0			0
Amortization of regulatory asset related to debt costs		16		0		14		2			1
Amortization of rate stabilization deferral		0		0		0		0			45
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 (f)		(32)		0		(32)		0			0
Bargain purchase gain related to Wolf Hollow Acquisition		(36)		(36)		0		0			0
Other		18		47		5		0			(6)

Total other non-cash operating activities	$	703	$	362	$	210	$	74		$	98

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		(9)		0		(20)		11			(25)
Other regulatory assets and liabilities		0		0		12		13			13
Other current assets		(166)		(46)		(13)		(59)	(e)		(92)
Other noncurrent assets and liabilities		83		(19)		50		7			(50)

Total changes in other assets and liabilities	$	(92)	$	(65)	$	29	$	(28)		$	(154)

_________

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

(d) See Note 3 - Mergers and Acquisitions for more information on merger-related commitments.

(e) Relates primarily to prepaid utility taxes.

Supplemental Balance Sheet Disclosures

September 30, 2012	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	11,890	(a)	$	5,910	(a)	$	2,906	$	2,765	$	2,579
Accounts receivable:
Allowance for uncollectible accounts		310			85			81		109		35

December 31, 2011	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	10,959	(b)	$	5,313	(b)	$	2,750	$	2,662	$	2,465
Accounts receivable:
Allowance for uncollectible accounts		199			29			78		92		38

___________

(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,161 million.

(b) Includes accumulated amortization of nuclear fuel in the reactor core of $1,784 million.

Accumulated Other Comprehensive Income Net Of Taxes

September 30, 2012	Exelon		Generation		ComEd		PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	459	$	730	$	0	$	0	$	0
Pension and non-pension postretirement benefit plans		(2,887)		0		0		0		0
Other comprehensive income—equity investment in CENG		23		23		0		0		0
Unrealized gain (loss) on marketable securities		0		(1)		0		1		0

Total accumulated other comprehensive income (loss)	$	(2,405)	$	752	$	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)

9 Months Ended

Sep. 30, 2012

Schedules Of Segment Reporting Information [Line Items]

Analysis and reconciliation of reportable segment information

Three Months Ended September 30, 2012 and 2011

		Generation(a)		ComEd		PECO		BGE		Other(b)		Intersegment Eliminations		Exelon
Total revenues(c):
	2012	$	4,017	$	1,484	$	806	$	720	$	336	$	(798)	$	6,565
	2011		2,821		1,784		946		0		206		(503)		5,254
Intersegment revenues(d):
	2012	$	459	$	0	$	1	$	4	$	334	$	(798)	$	0
	2011		304		1		2		0		203		(503)		7
Net income (loss):
	2012	$	87	$	90	$	123	$	0	$	(3)	$	0	$	297
	2011		386		112		105		0		(1)		0		602
Total assets:
	September 30, 2012	$	41,090	$	22,471	$	9,661	$	7,504	$	10,150	$	(12,523)	$	78,353
	December 31, 2011		27,433		22,638		9,156		0		6,162		(10,394)		54,995

__________

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

Nine Months Ended September 30, 2012 and 2011

												Intersegment
		Generation (a)		ComEd		PECO		BGE(b)		Other(c)		Eliminations		Exelon
Total revenues(d):
	2012	$	10,509	$	4,154	$	2,396	$	1,388	$	1,049	$	(2,291)	$	17,205
	2011		7,919		4,694		2,942		0		579		(1,429)		14,705
Intersegment revenues(e):
	2012	$	1,233	$	2	$	3	$	7	$	1,050	$	(2,291)	$	4
	2011		856		2		4		0		576		(1,429)		9
Net income (loss):
	2012	$	419	$	219	$	300	$	(50)	$	(101)	$	0	$	787
	2011		1,325		295		314		0		(45)		0		1,889

__________

(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2012 include revenue from sales to PECO of $407 million and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $ (30) million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the nine months ended September 30, 2011 intersegment revenues for Generation include revenue from sales to PECO of $394 million in the Mid-Atlantic region, and sales to ComEd of $450 million in the Midwest region.

(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through September 30, 2012.

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

Schedules Of Segment Reporting Information [Line Items]

Analysis and reconciliation of reportable segment revenues for Generation

Three Months Ended September 30, 2012 and 2011

Generation total revenues:
	2012						2011
	Revenues from external customers (a)		Intersegment revenues		Total Revenues		Revenues from external customers (a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	1,428	$	(11)	$	1,417	$	1,032	$	-	$	1,032
Midwest		1,193		7		1,200		1,385		-		1,385
New England		390		1		391		2		-		2
New York		183		2		185		0		-		0
ERCOT		532		1		533		307		-		307
Other Regions (b)		317		12		329		77		-		77
Total Revenues for Reportable Segments	$	4,043	$	12	$	4,055	$	2,803	$	-	$	2,803
Other (c)		(35)		(3)		(38)		18		-		18
Total Generation Consolidated Operating Revenues	$	4,008	$	9	$	4,017	$	2,821	$	-	$	2,821

(a) Includes all wholesale and retail electric 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.

Nine Months Ended September 30, 2012 and 2011

Generation total revenues:
	2012						2011
	Revenues from external customers (a)		Intersegment revenues		Total Revenues		Revenues from external customers (a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	3,832	$	(43)	$	3,789	$	3,102	$	-	$	3,102
Midwest		3,600		19		3,619		4,151		-		4,151
New England		776		36		812		8		-		8
New York		394		(22)		372		0		-		0
ERCOT		1,073		1		1,074		507		-		507
Other Regions (b)		611		40		651		169		-		169
Total Revenues for Reportable Segments	$	10,286	$	31	$	10,317	$	7,937	$	-	$	7,937
Other (c)		212		(20)		192		(18)		-		(18)
Total Generation Consolidated Operating Revenues	$	10,498	$	11	$	10,509	$	7,919	$	-	$	7,919

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

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

Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation

Three Months Ended September 30, 2012 and 2011

Generation total revenues net of purchased power and fuel expense:
	2012						2011
	RNF from external customers (a)		Intersegment RNF		Total RNF		RNF from external customers (a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	919	$	(11)	$	908	$	835	$	-	$	835
Midwest		723		7		730		852		-		852
New England		80		1		81		1		-		1
New York		11		2		13		0		-		0
ERCOT		158		0		158		103		-		103
Other Regions (b)		30		12		42		(4)		-		(4)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	1,921	$	11	$	1,932	$	1,787	$	-	$	1,787
Other (c)		(26)		(11)		(37)		(37)		-		(37)
Total Generation Revenues net of purchased power and fuel expense	$	1,895	$	0	$	1,895	$	1,750	$	-	$	1,750

Nine Months Ended September 30, 2012 and 2011

Generation total revenues net of purchased power and fuel expense:
	2012						2011
	RNF from external customers (a)		Intersegment RNF		Total RNF		RNF from external customers (a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,605	$	(44)	$	2,561	$	2,567	$	-	$	2,567
Midwest		2,291		19		2,310		2,704		-		2,704
New England		144		36		180		6		-		6
New York		82		(22)		60		0		-		0
ERCOT		311		1		312		94		-		94
Other Regions (b)		49		41		90		(10)		-		(10)
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	5,482	$	31	$	5,513	$	5,361	$	-	$	5,361
Other (c)		9		(31)		(22)		(237)		-		(237)
Total Generation Revenues net of purchased power and fuel expense	$	5,491	$	0	$	5,491	$	5,124	$	-	$	5,124

(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.

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.

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Significant Accounting Policies (Details)	Sep. 30, 2012
Exelon Generation Co L L C [Member]
Consolidation Percentages Detail Tagging [Abstract]
Exelon Percentage ownership of Exelon SHC, LLC	50.01%

Basis of Presentation (Details)

3 Months Ended

9 Months Ended

Sep. 30, 2012

USD ($)

VIE

Sep. 30, 2011

USD ($)

Sep. 30, 2012

USD ($)

VIE

Sep. 30, 2011

USD ($)

$ 398,000,000

471,000,000

869,000,000

269,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

573,000,000

Total Liabilities

842,000,000

^[1]

622,000,000

^[1]

312,000,000

^[1]

98,000,000

Letter of Credit [Member]

^[1]

212,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

8,000,000

Investments [Member]

Payment Guarantee [Member]

78,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Power Contract Monetization Entities [Member]

5,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

280,000,000

^[1]

217,000,000

Power Contract Monetization Entities [Member] | Letter of Credit [Member]

^[1]

63,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other Than Power Contract Monetization Entities [Member]

8,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

342,000,000

^[1]

95,000,000

^[1]

98,000,000

Other Than Power Contract Monetization Entities [Member] | Investments [Member]

^[1]

149,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Other Than Power Contract Monetization Entities [Member] | Payment Guarantee [Member]

78,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

5,000,000

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

348,000,000

432,000,000

780,000,000

193,000,000

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

235,000,000

Total Liabilities

$ 428,000,000

Number of Variable Interest Entities not consolidated by equity holders | VIE

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

$ 622,000,000

^[1]

312,000,000

^[1]

98,000,000

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

^[1]

212,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

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

8,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

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

78,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Exelon Generation Co L L C [Member] | Power Contract Monetization Entities [Member]

5,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

280,000,000

^[1]

217,000,000

Exelon Generation Co L L C [Member] | Power Contract Monetization Entities [Member] | Letter of Credit [Member]

^[1]

63,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Exelon Generation Co L L C [Member] | Other Than Power Contract Monetization Entities [Member]

8,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

342,000,000

^[1]

95,000,000

^[1]

98,000,000

Exelon Generation Co L L C [Member] | Other Than Power Contract Monetization Entities [Member] | Investments [Member]

^[1]

149,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Exelon Generation Co L L C [Member] | Other Than Power Contract Monetization Entities [Member] | Payment Guarantee [Member]

78,000,000

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member]

5,000,000

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Current assets

69,000,000

Noncurrent assets

516,000,000

Current liabilities

230,000,000

159,000,000

Consolidated Variable Interest Entity [Abstract]

Parental guarantee provided

75,000,000

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

49,000,000

49,000,000

75,000,000

Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member]

299,000,000

Total Liabilities

374,000,000

Consolidated Variable Interest Entity [Abstract]

Remittance of payments received from customers for rate stabilization to BondCo.

$ 27,000,000

$ 62,000,000

$ 65,000,000

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

Regulatory Matters (Details)

1 Months Ended

9 Months Ended

Jun. 01, 2013

USD ($)

Jul. 27, 2012

USD ($)

Sep. 30, 2008

USD ($)

Sep. 30, 2012

USD ($)

SmartMeters

Years

Sep. 30, 2011

USD ($)

Jun. 01, 2015

Feb. 29, 2012

USD ($)

Dec. 31, 2011

USD ($)

^[1]

$ 203,000,000

$ 68,000,000

^[2]

(18,000,000)

(5,000,000)

185,000,000

63,000,000

6,192,000,000

4,518,000,000

786,000,000

390,000,000

299,000,000

197,000,000

Nuclear Decommissioning [Member]

4,000,000,000

3,627,000,000

2,383,000,000

2,222,000,000

Removal Costs [Member]

94,000,000

61,000,000

Energy Efficiency Demand Response Programs [Member]

1,397,000,000

1,185,000,000

82,000,000

49,000,000

Electric Transmission And Distribution Tax Repairs [Member]

33,000,000

69,000,000

18,000,000

19,000,000

Over Recovered Distribution Services Costs [Member]

138,000,000

151,000,000

45,000,000

Over Recovered Uncollectible Accounts Expense [Member]

10,000,000

15,000,000

Over Recovered Energy And Transmission Costs [Member]

39,000,000

42,000,000

Over-Recovered Universal Service Fund Costs [Member]

3,000,000

Over-Recovered AEPS Costs [Member]

1,000,000

8,000,000

Customer Rate Credit [Member]

1,000,000

Regulatory Liabilities Other [Member]

1,000,000

^[1]

56,000,000

16,000,000

^[2]

(6,000,000)

Energy Infrastructure Modernization Act [Abstract]

50,000,000

16,000,000

Additional investment to modernize system and implement smart grid technology.

2,600,000,000

Annual contribution to fund customer assistance programs

10,000,000

Contribution to a science and technology innovation trust

15,000,000

Subsequent annual contributions to the trust

$ 4,000,000

Time period for AMI Deployment | Years

Planned capital spend by a utility under state enacted legislation

$ 233,000,000

Annual revenue requirement reduction

168,000,000

Annual revenue requirement reduction incremental to proposal

110,000,000

Annual revenue requirement incremental reduction attributable to alternative recovery

50,000,000

Annual revenue requirement incremental reduction attributable to pensions

35,000,000

Annual revenue requirement incremental reduction attributable to incentives

10,000,000

Annual revenue requirement incremental reduction attributable to other adjustments

15,000,000

Regulatory asset reduction due to final order

100,000,000

Deferral of AMI plan

50,000,000

Deferral of additional capital investment

15,000,000

Expected revenue adjustment in subsequent quarter

135,000,000

Distribution Rate Case [Abstract]

Rate of return on common equity electric distribution

10.30%

Intervenor potential refund submitted in testimony

$ 37,000,000

Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract]

Increase in electric delivery service revenue requirement resulting from regulatory order in rate case

$ 274,000,000

Annual Transmission Formula Rate Update [Abstract]

Gross transmission revenue requirement

450,000,000

$ 438,000,000

Transmission revenue true up

5,000,000

16,000,000

Net transmission revenue requirement

445,000,000

$ 422,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Advanced metering infrastructure pilot program [Abstract]

$ 124,000,000

Collections Under Rider Amp

24,000,000

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%

$ 589,000,000

699,000,000

511,000,000

657,000,000

172,000,000

137,000,000

Commonwealth Edison Co [Member] | One Year From Balance Sheet Date [Member]

3,206,000,000

3,042,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | More Than One And Within Two Years From Balance Sheet Date [Member]

8,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | More Than Two And Within Three Years From Balance Sheet Date [Member]

57,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | More Than Three And Within Four Years From Balance Sheet Date [Member]

9,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | More Than Four And Within Five Years From Balance Sheet Date [Member]

20,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | More Than Five Years From Balance Sheet Date And Thereafter [Member]

25,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member]

5,000,000

Commonwealth Edison Co [Member] | Removal Costs [Member]

2,021,000,000

1,857,000,000

73,000,000

61,000,000

Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]

1,185,000,000

37,000,000

49,000,000

Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Commonwealth Edison Co [Member] | Over Recovered Distribution Services Costs [Member]

45,000,000

Commonwealth Edison Co [Member] | Over Recovered Uncollectible Accounts Expense [Member]

10,000,000

15,000,000

Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]

7,000,000

12,000,000

Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

Commonwealth Edison Co [Member] | Over-Recovered AEPS Costs [Member]

Commonwealth Edison Co [Member] | Customer Rate Credit [Member]

^[1]

72,000,000

52,000,000

^[2]

(7,000,000)

(5,000,000)

Discount on purchased receivables

$ 65,000,000

47,000,000

1.00%

Distribution Rate Case [Abstract]

Increase in gas delivery service revenue resulting from rate case settlement

$ 20,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Smart Meter and Smart Grid Investments [Abstract]

$ 86,000,000

Expected number of smart meters to be deployed during the first phase of Smart Meter Installment Plan | SmartMeters

600,000

Estimated Cost related to first phase deployment of Smart Meter Procurement and Installation Plan

$ 415,000,000

Smart grid investment grant amount

200,000,000

Amount of Smart grid investment grant utilized during the first phase deployment

$ 140,000,000

Number of previously installed smart meters to be replaced | SmartMeters

186,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

$ 16,000,000

Reimbursements received from the DOE

130,000,000

Carrying value of originally installed Smart Meters, net of reimbursements from DOE

18,000,000

Amount of reimbursements received from the DOE applied to the originally installed Smart Meters.

16,000,000

Energy Efficiency Program [Abstract]

Cumulative Consumption Reduction Targets

2.90%

Natural Gas Distribution Rate Case [Abstract]

Gas Distribution Tax Repairs Refund

54,000,000

Natural Gas Supplier Tariff [Abstract]

Natural gas supplier tariff total collateral

14,000,000

1,323,000,000

1,216,000,000

42,000,000

39,000,000

105,000,000

60,000,000

Regulatory Liabilities Table Footnote Data [Abstract]

582,000,000

585,000,000

Purchased Natural Gas Cost Over-Recovery

5,000,000

Electric Supply Cost Over-Recovery

32,000,000

25,000,000

Electric Transmission Costs Under-Recovery

5,000,000

Purchased Natural Gas Costs Under-Recovery

$ 2,000,000

PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]

Energy Efficiency Program [Abstract]

Maximum civil penalty under Act 129

$ 20,000,000

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%

PECO Energy Co [Member] | One Year From Balance Sheet Date [Member]

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | More Than One And Within Two Years From Balance Sheet Date [Member]

$ 6,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | More Than Two And Within Three Years From Balance Sheet Date [Member]

9,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | More Than Three And Within Four Years From Balance Sheet Date [Member]

11,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | More Than Four And Within Five Years From Balance Sheet Date [Member]

13,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | More Than Five Years From Balance Sheet Date And Thereafter [Member]

21,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

PECO Energy Co [Member] | Nuclear Decommissioning [Member]

26,000,000

PECO Energy Co [Member] | Removal Costs [Member]

362,000,000

365,000,000

PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]

45,000,000

PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

33,000,000

69,000,000

18,000,000

19,000,000

PECO Energy Co [Member] | Over Recovered Distribution Services Costs [Member]

138,000,000

151,000,000

PECO Energy Co [Member] | Over Recovered Uncollectible Accounts Expense [Member]

PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]

^[3]

32,000,000

30,000,000

PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

3,000,000

PECO Energy Co [Member] | Over-Recovered AEPS Costs [Member]

1,000,000

8,000,000

PECO Energy Co [Member] | Customer Rate Credit [Member]

PECO Energy Co [Member] | Regulatory Liabilities Other [Member]

PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member]

1,000,000

5,000,000

49,000,000

^[1]

75,000,000

61,000,000

^[2]

(5,000,000)

(3,000,000)

Requested increase in electric revenues

70,000,000

58,000,000

Distribution Rate Case [Abstract]

$ 131,000,000

Requested increase in gas revenues

$ 45,000,000

Requested rate of return on common equity

10.50%

PJM Transmission Rate Design And Operating Agreements Abstract

Smart Meter and Smart Grid Investments [Abstract]

$ 165,000,000

Estimated number of smart meters to be installed | SmartMeters

2,000,000

Smart grid investment grant amount

$ 200,000,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

13,000,000

Reimbursements received from the DOE

126,000,000

Total Projected smart meter smart grid spend

480,000,000

New Electric Generation [Abstract]

Megawatt capacity of new generating plant | MW

700

Maryland Electric And Natural Gas Distribution Rate Cases [Abstract]

Deferral of total costs

$ 19,000,000

Deferral of storm costs

$ 16,000,000

534,000,000

550,000,000

189,000,000

174,000,000

22,000,000

18,000,000

Baltimore Gas and Electric Company [Member] | One Year From Balance Sheet Date [Member]

212,000,000

200,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | More Than One And Within Two Years From Balance Sheet Date [Member]

(32,000,000)

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | More Than Two And Within Three Years From Balance Sheet Date [Member]

(20,000,000)

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | More Than Three And Within Four Years From Balance Sheet Date [Member]

44,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | More Than Four And Within Five Years From Balance Sheet Date [Member]

115,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | More Than Five Years From Balance Sheet Date And Thereafter [Member]

52,000,000

PJM Transmission Rate Design And Operating Agreements Abstract

Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member]

6,000,000

Baltimore Gas and Electric Company [Member] | Removal Costs [Member]

21,000,000

18,000,000

Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]

212,000,000

200,000,000

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Baltimore Gas and Electric Company [Member] | Over Recovered Distribution Services Costs [Member]

Baltimore Gas and Electric Company [Member] | Over Recovered Uncollectible Accounts Expense [Member]

Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]

Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member]

Baltimore Gas and Electric Company [Member] | Over-Recovered AEPS Costs [Member]

Baltimore Gas and Electric Company [Member] | Customer Rate Credit [Member]

$ 0

1,000,000

Exelon Corporate [Member] | Gas Distribution Tax Repairs [Member]

5,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

$ 49,000,000

[1]	PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
[2]	For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.
[3]	Relates to the over-recovered electric supply costs under the GSA as of September 30, 2012. Includes $5 million related to the over-recovered natural gas costs under the PGC and $25 million related to the over-recovered electric supply costs under the GSA as of December 31, 2011.

Merger and Acquisitions (Details)

1 Months Ended

3 Months Ended

9 Months Ended

Mar. 31, 2012

USD ($)

Sep. 30, 2012

USD ($)

$ / shares

Sep. 30, 2011

USD ($)

$ / shares

Sep. 30, 2012

USD ($)

Years

Days

$ / shares

Sep. 30, 2011

USD ($)

$ / shares

Business Combination, Bargain Purchase [Abstract]

$ 18,000,000

$ 43,000,000

Business Combination, Bargain Purchase, Gain Recognized, Amount

36,000,000

Business Acquisition, Impact Of Merger [Abstract]

$ 6,565,000,000

5,254,000,000

$ 17,205,000,000

14,705,000,000

Business Acquisition, Costs Recognized Post Merger [Abstract]

297,000,000

602,000,000

787,000,000

1,892,000,000

BGE rate credit of $100 per residential customer

113,000,000

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

Charitable contributions at $7 million per year for 10 years

70,000,000

State funding for offshore wind development projects

32,000,000

Miscellaneous tax benefits

(2,000,000)

Total

328,500,000

Business Acquisition Charitable Contributions Per Year

7,000,000

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

Business Acquisition, Proceeds Assets Held For Sale

356,000,000

Business Acquisition, Gain (Loss) On Sale Of Assets Held For Sale

(278,000,000)

Business Acquisition, Fair Value of Assets Held For Sale

339,000,000

Stock Compensation Expense

8,000,000

117,000,000

3,000,000

6,000,000

7,000,000

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

11,000,000

130,000,000

Minimum [Member]

Business Acquisition, Construction Cost

$ 95,000,000

Business Acquisition, Construction Time Frame | Years

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 | Years

Business Acquisition, Expected New Generation Mwh | MW

300

118,000,000

$ 0

$ 83,000,000

Payments

9,000,000

10,000,000

Constellation Energy Group Acquisition [Member] | Severance [Member]

120,000,000

Constellation Energy Group Acquisition [Member] | One-time Termination Benefits [Member]

^[1]

7,000,000

114,000,000

Constellation Energy Group Acquisition [Member] | Stock Compensation Plan [Member]

^[2]

1,000,000

3,000,000

Constellation Energy Group Acquisition [Member] | Other Severance Charges [Member]

3,000,000

6,000,000

^[3]

7,000,000

Finite lived intangible assets accumulated amortization

1,953,000,000

(737,000,000)

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

1,216,000,000

285,000,000

439,000,000

119,000,000

61,000,000

12,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Acquisition, Purchase Price Allocation [Abstract]

87,000,000

671,000,000

Business Acquisition, Purchase Price Allocation, Current Assets

4,936,000,000

Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment

9,240,000,000

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

2,668,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired

23,201,000,000

Business Acquisition, Purchase Price Allocation, Current Liabilities

3,431,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities

4,553,000,000

Business Acquisition, Purchase Price Allocation, Liability Contracts

1,722,000,000

Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt

6,038,000,000

Business Combination Acquisition Of Less Than 100 Percent Noncontrolling Interest Fair Value

92,000,000

Business Acquisition, Purchase Price Allocation, Liabilities Assumed

15,836,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net

7,365,000,000

Business Acquisition, Pro Forma Information [Abstract]

Business Acquisition, Pro Forma Revenue

6,841,000,000

8,219,000,000

^[4]

20,084,000,000

23,839,000,000

^[4]

Business Acquisition, Pro Forma Net Income (Loss)

$ 492,000,000

$ 379,000,000

^[4]

$ 1,439,000,000

$ 1,119,000,000

^[4]

Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares

$ 0.58

$ 0.45

^[4]

$ 1.79

$ 1.32

^[4]

Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares

$ 0.57

$ 0.44

^[4]

$ 1.79

$ 1.31

^[4]

Business Acquisition, Pro Forma Nonrecurring Cost

$ 74,000,000

$ 242,000,000

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, Divesture Sales Days | Days

150

Business Acquisition, Divesture Sales Days Extension | Days

Business Acquisition, Proceeds Assets Held For Sale

366,000,000

$ 366,000,000

Business Acquisition, Gain (Loss) On Sale Of Assets Held For Sale

(268,000,000)

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Combination, Bargain Purchase [Abstract]

5,000,000

6,000,000

Business Combination, Bargain Purchase, Gain Recognized, Amount

36,000,000

Business Acquisition, Impact Of Merger [Abstract]

4,017,000,000

2,821,000,000

10,509,000,000

7,919,000,000

Business Acquisition, Costs Recognized Post Merger [Abstract]

87,000,000

386,000,000

419,000,000

1,325,000,000

Charitable contributions at $7 million per year for 10 years

35,000,000

Total

35,000,000

Stock Compensation Expense

4,000,000

68,000,000

2,000,000

4,000,000

4,000,000

Exelon Generation Co L L C [Member] | One-time Termination Benefits [Member]

^[5]

6,000,000

76,000,000

Payments

2,000,000

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

1,000,000

^[6]

1,000,000

^[7]

30,000,000

40,000,000

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

34,000,000

Exelon Generation Co L L C [Member] | Constellation Energy Group Acquisition [Member] | Stock Compensation Plan [Member]

^[1]

4,000,000

31,000,000

Exelon Generation Co L L C [Member] | Constellation Energy Group Acquisition [Member] | Other Severance Charges [Member]

1,000,000

2,000,000

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

^[3]

2,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Acquisition, Purchase Price Allocation [Abstract]

79,000,000

283,000,000

Business Acquisition, Purchase Price Allocation, Current Assets

3,638,000,000

Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment

3,948,000,000

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

14,469,000,000

Business Acquisition, Purchase Price Allocation, Current Liabilities

2,798,000,000

Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities

1,837,000,000

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

92,000,000

Business Acquisition, Purchase Price Allocation, Liabilities Assumed

9,211,000,000

Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net

5,258,000,000

Business Acquisition, Pro Forma Information [Abstract]

Business Acquisition, Pro Forma Revenue

4,293,000,000

5,133,000,000

^[8]

12,753,000,000

14,996,000,000

^[8]

Business Acquisition, Pro Forma Net Income (Loss)

282,000,000

163,000,000

^[8]

$ 805,000,000

690,000,000

^[6]

Business Acquisition, Pro Forma Nonrecurring Cost

69,000,000

318,000,000

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 Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

DOE Loan Receipt

69,000,000

$ 69,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Acquisition, Impact Of Merger [Abstract]

2,000,000

1,484,000,000

1,784,000,000

4,154,000,000

4,694,000,000

90,000,000

112,000,000

219,000,000

295,000,000

Stock Compensation Expense

1,000,000

16,000,000

^[7]

1,000,000

^[7]

^[7]

1,000,000

Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member]

^[5]

2,000,000

18,000,000

^[7]

2,000,000

2,000,000

16,000,000

Merger related regulatory asset

2,000,000

34,000,000

18,000,000

Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member] | Severance [Member]

Commonwealth Edison Co [Member] | Constellation Energy Group Acquisition [Member]

^[1]

2,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

2,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Acquisition, Impact Of Merger [Abstract]

4,000,000

1,000,000

806,000,000

946,000,000

2,396,000,000

2,942,000,000

123,000,000

105,000,000

300,000,000

314,000,000

1,000,000

8,000,000

PECO Energy Co [Member] | Constellation Energy Group Acquisition [Member]

^[5]

1,000,000

8,000,000

1,000,000

8,000,000

PECO Energy Co [Member] | Constellation Energy Group Acquisition [Member]

Business Acquisition Cost Of Acquired Entity [Abstract]

3,000,000

13,000,000

Business Acquisition, Impact Of Merger [Abstract]

720,000,000

745,000,000

2,032,000,000

2,394,000,000

Revenues Impact

720,000,000

1,388,000,000

Net Income Loss Impact

(49,000,000)

Business Acquisition, Costs Recognized Post Merger [Abstract]

$ 2,000,000

(14,000,000)

$ 99,000,000

Business Acquisition, Regulatory Rate Credit Per Customer

100

BGE rate credit of $100 per residential customer

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

1,000,000

18,000,000

^[9]

^[9]

1,000,000

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member]

^[5]

1,000,000

19,000,000

^[9]

Payments

1,000,000

12,000,000

1,000,000

7,000,000

Merger related regulatory asset

11,000,000

22,000,000

19,000,000

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member] | Severance [Member]

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member] | Other Severance Charges [Member]

^[1]

11,000,000

Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member]

^[3]

1,000,000

Business Acquisition Cost Of Acquired Entity [Abstract]

Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract]

1,000,000

$ 155,000,000

Business Acquisition, Expected New Generation Development Time Frame | Years

Business Acquisition, Equity Interests Issued or Issuable [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

7,365,000,000

$ 7,365,000,000

Business Acquisition, Equity Interest Issued Or Issuable, Exchange Ratio | shares

0.930

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

^[6]

187,450,000

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

^[6]

7,294,000,000

$ 7,294,000,000

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

11,300,000

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

71,000,000

$ 71,000,000

Customer Relationships [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life | Years

12.4

Finite lived intangible assets accumulated amortization

214,000,000

$ 214,000,000

(9,000,000)

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

205,000,000

8,000,000

19,000,000

19,000,000

19,000,000

Trade Names [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member]

$ 19,000,000

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life | Years

10.0

Finite lived intangible assets accumulated amortization

243,000,000

$ 243,000,000

(14,000,000)

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

229,000,000

10,000,000

24,000,000

24,000,000

24,000,000

Power Supply Contracts [Member]

24,000,000

Finite lived intangible assets accumulated amortization

(224,000,000)

$ (224,000,000)

Power Supply Contracts [Member] | Constellation Energy Group Acquisition [Member] | Total Assets [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life | Years

^[10]

1.5

Finite lived intangible assets accumulated amortization

^[10]

1,496,000,000

$ 1,496,000,000

^[10]

(714,000,000)

Finite Lived Intangible Assets Future Amortization Expense [Abstract]

^[10]

$ 782,000,000

782,000,000

^[10]

267,000,000

^[10]

396,000,000

^[10]

76,000,000

^[10]

18,000,000

Impact Of Transactions Under Agreements [Abstract]

^[10]

$ (31,000,000)

[1]	Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits.
[2]	One-time termination benefits began to be recognized in the second quarter of 2012.
[3]	Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services.
[4]	The amounts above include non-recurring costs directly related to the merger of $74 million and $242 million for the three and nine months ended September 30, 2011, respectively.
[5]	The amounts above include $0 million and $40 million at Generation, $2 million and $16 million at ComEd, $1 million and $8 million at PECO, and $1 million and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2012, respectively.
[6]	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.
[7]	ComEd established regulatory assets of $18 million, as of September 30, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
[8]	The amounts above include non-recurring costs directly related to the merger of $69 million and $318 million for the three and nine months ended September 30, 2011, respectively.
[9]	Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of September 30, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.
[10]	Includes the fair value of BGE's power and gas supply contracts for which an offsetting regulatory asset was also recorded

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

1 Months Ended

3 Months Ended

7 Months Ended

9 Months Ended

May 31, 2011

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Amortization of energy contract assets and liabilities

^[1]

$ 731,000,000

Power Purchase Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

$ (282,000,000)

(86,000,000)

$ (86,000,000)

(86,000,000)

Power Service Agency Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

^[2]

1,000,000

2,000,000

Amortization of energy contract assets and liabilities

2,000,000

Administrative Services Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

14,000,000

30,000,000

5,000,000

$ 5,000,000

5,000,000

Purchase of nuclear output by EDF (as a percent)

49.99%

Maximum cost of service per month

$ 358,000

Impact Of Transactions Under Agreements [Abstract]

CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount

$ 459,000,000

$ 304,000,000

1,233,000,000

$ 856,000,000

$ 63,000,000

$ 43,000,000

Percentage of request for borrowings submitted to entity (as a percent)

50.00%

Percentage of request for borrowings submitted to entity's subsidiaries (as a percent)

50.00%

Amortization of energy contract assets and liabilities

^[1]

$ 811,000,000

Debt Instrument, Basis Spread on Variable Rate

2.50%

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

50.01%

Basis difference in investment in CENG

$ 204,000,000

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

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] | Maximum [Member]

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 [Member]

Schedule of Equity Method Investments [Line Items]

CENG

58,000,000

53,000,000

Amortization of basis difference in CENG

(57,000,000)

(131,000,000)

Total equity investment earnings (losses) - CENG

1,000,000

(78,000,000)

Exelon Generation Co L L C [Member] | Power Purchase Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

(282,000,000)

$ (541,000,000)

(86,000,000)

Exelon Generation Co L L C [Member] | Power Service Agency Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

^[2]

1,000,000

2,000,000

Amortization of energy contract assets and liabilities

2,000,000

Exelon Generation Co L L C [Member] | Administrative Services Agreement [Member]

Impact Of Transactions Under Agreements [Abstract]

Amount receivable from (payable to) related to agreements with CENG

14,000,000

30,000,000

$ 5,000,000

[1]	Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income
[2]

Goodwill (Details)	9 Months Ended
Goodwill (Details)	Sep. 30, 2012 USD ($)
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 2,625,000,000
Goodwill, ending balance	2,625,000,000
Commonwealth Edison Co [Member]
Goodwill, Impaired [Abstract]
Annual revenue requirement reduction	$ 168,000,000
Percentage decrease in fair value	10.00%
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 2,625,000,000
Goodwill, ending balance	2,625,000,000
Commonwealth Edison Co [Member] \| Maximum [Member]
Goodwill, Impaired [Abstract]
Annual revenue requirement reduction	130,000,000
Commonwealth Edison Co [Member] \| Minimum [Member]
Goodwill, Impaired [Abstract]
Annual revenue requirement reduction	$ 75,000,000

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.

Reference 1: 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 2: 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 3: 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 4: 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 5: 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=6905597&loc=d3e13816-109267

Reference 6: 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 7: 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 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.

Accounts Receivable (Details) - USD ($)	Sep. 30, 2012	Dec. 31, 2011
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	$ (310,000,000)	$ (199,000,000)
Accounts Receivable Additional Disclosures [Abstract]
Gross Accounts Receivable Pledged as Collateral	314,000,000	329,000,000
Exelon Generation Co L L C [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	(85,000,000)	(29,000,000)
Commonwealth Edison Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	(81,000,000)	(78,000,000)
PECO Energy Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	(109,000,000)	(92,000,000)
Accounts Receivable Additional Disclosures [Abstract]
Gross Accounts Receivable Pledged as Collateral	314,000,000	329,000,000
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables	21,000,000	21,000,000
Installment plan receivables uncollectible accounts reserve	(18,000,000)	(17,000,000)
PECO Energy Co [Member] \| Low To Medium Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(1,000,000)	(1,000,000)
PECO Energy Co [Member] \| Medium Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(4,000,000)	(3,000,000)
PECO Energy Co [Member] \| High Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(13,000,000)	(13,000,000)
Baltimore Gas and Electric Company [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	$ (35,000,000)	$ (38,000,000)

Property, Plant and Equipment (Details) - USD ($)

Sep. 30, 2012

Dec. 31, 2011

$ (11,890,000,000)

^[1]

$ (10,959,000,000)

^[2]

Property Plant And Equipment Footnotes [Abstract]

43,914,000,000

32,570,000,000

2,161,000,000

1,784,000,000

(5,910,000,000)

^[1]

(5,313,000,000)

^[2]

Property Plant And Equipment Footnotes [Abstract]

18,708,000,000

13,475,000,000

2,161,000,000

1,784,000,000

(2,906,000,000)

(2,750,000,000)

13,611,000,000

13,121,000,000

(2,765,000,000)

(2,662,000,000)

5,996,000,000

5,874,000,000

(2,579,000,000)

(2,465,000,000)

$ 5,378,000,000

$ 5,132,000,000

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,161 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $1,784 million.

The cumulative amount of depreciation, depletion and amortization (related to property, plant and equipment, but not including land) that has been recognized in the income statement.

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair Value of Financial Assets and Liabilities (Fair Value By Balance Sheet Grouping) (Details) - USD ($)	Sep. 30, 2012	Dec. 31, 2011
Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	$ 289,000,000	$ 737,000,000
Long-term debt (including amounts due within one year)	18,715,000,000	12,627,000,000
Long-term debt to financing trusts	649,000,000	390,000,000
Spent nuclear fuel obligation	1,020,000,000	1,019,000,000
Preferred securities of subsidiary	87,000,000	87,000,000
Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		737,000,000
Long-term debt (including amounts due within one year)		14,488,000,000
Long-term debt to financing trusts		358,000,000
Spent nuclear fuel obligation		886,000,000
Preferred securities of subsidiary		79,000,000
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	4,000,000
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	285,000,000
Long-term debt (including amounts due within one year)	20,762,000,000
Long-term debt to financing trusts	650,000,000
Spent nuclear fuel obligation	780,000,000
Preferred securities of subsidiary	83,000,000
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)	38,000,000
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	11,000,000	2,000,000
Long-term debt (including amounts due within one year)	7,383,000,000	3,677,000,000
Spent nuclear fuel obligation	1,020,000,000	1,019,000,000
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		2,000,000
Long-term debt (including amounts due within one year)		4,231,000,000
Spent nuclear fuel obligation		886,000,000
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]
Short-term liabilities	11,000,000
Long-term debt (including amounts due within one year)	7,839,000,000
Spent nuclear fuel obligation	780,000,000
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)	20,000,000
Commonwealth Edison Co [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	35,000,000
Long-term debt (including amounts due within one year)	5,217,000,000	5,665,000,000
Long-term debt to financing trusts	206,000,000	206,000,000
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)		6,540,000,000
Long-term debt to financing trusts		184,000,000
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]
Short-term liabilities	35,000,000
Long-term debt (including amounts due within one year)	6,297,000,000
Long-term debt to financing trusts	208,000,000
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)	18,000,000
PECO Energy Co [Member] \| Carrying Reported Amount Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities	225,000,000	225,000,000
Long-term debt (including amounts due within one year)	2,322,000,000	1,972,000,000
Long-term debt to financing trusts	184,000,000	184,000,000
Preferred securities of subsidiary	87,000,000	87,000,000
PECO Energy Co [Member] \| Estimate Of Fair Value Fair Value Disclosure [Member]
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract]
Short-term liabilities		225,000,000
Long-term debt (including amounts due within one year)		2,295,000,000
Long-term debt to financing trusts		174,000,000
Preferred securities of subsidiary		79,000,000
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	225,000,000
Long-term debt (including amounts due within one year)	2,682,000,000
Long-term debt to financing trusts	180,000,000
Preferred securities of subsidiary	83,000,000
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)	2,210,000,000	2,101,000,000
Long-term debt to financing trusts	258,000,000	258,000,000
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)		2,377,000,000
Long-term debt to financing trusts		$ 256,000,000
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)	2,547,000,000
Long-term debt to financing trusts	$ 264,000,000

Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) - USD ($)

Sep. 30, 2012

Dec. 31, 2011

$ 1,117,000,000

$ 861,000,000

^[1]

^[2],[3]

(800,000,000)

19,000,000

(101,000,000)

(73,000,000)

10,939,000,000

9,268,000,000

(1,030,000,000)

(311,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

9,909,000,000

8,957,000,000

101,000,000

73,000,000

Mark-to-market derivative liabilities (current liabilities)

503,000,000

521,000,000

112,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

407,000,000

126,000,000

Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

319,000,000

562,000,000

1,452,000,000

1,275,000,000

1,906,000,000

1,822,000,000

3,358,000,000

3,097,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,100,000,000

1,047,000,000

Debt securities issued by states of the United States and political subdivisions of the states

355,000,000

541,000,000

84,000,000

16,000,000

1,734,000,000

778,000,000

31,000,000

357,000,000

Residential mortgage-backed securities (non-agency)

47,000,000

83,000,000

15,000,000

5,000,000

9,000,000

47,000,000

3,375,000,000

2,874,000,000

70,000,000

13,000,000

Nuclear decommissioning trust fund investments subtotal

16,000,000

18,000,000

^[4]

7,138,000,000

6,564,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

2,000,000

(57,000,000)

Pledged Assets For Zion Station Decommissioning [Member]

21,000,000

35,000,000

20,000,000

30,000,000

41,000,000

65,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

93,000,000

80,000,000

Debt securities issued by states of the United States and political subdivisions of the states

58,000,000

65,000,000

260,000,000

314,000,000

60,000,000

121,000,000

6,000,000

10,000,000

43,000,000

20,000,000

520,000,000

610,000,000

64,000,000

37,000,000

Pledged assets for Zion Station decommissioning subtotal

1,000,000

13,000,000

^[5]

626,000,000

725,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from pledged assets

9,000,000

Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,000,000

^[6],[7]

69,000,000

34,000,000

71,000,000

36,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(54,000,000)

Supplemental executive retirement plan fair value

54,000,000

15,000,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

28,000,000

25,000,000

Derivative Financial Instruments Assets [Member]

857,000,000

5,532,000,000

1,777,000,000

Effect of netting and allocation of collateral received/(paid)

4,841,000,000

288,000,000

^[8]

(8,530,000,000)

(1,855,000,000)

^[9]

1,843,000,000

1,067,000,000

^[8]

Derivative Financial Instruments Liabilities [Member]

125,000,000

15,000,000

(13,000,000)

(4,390,000,000)

(1,257,000,000)

Effect of netting and allocation of collateral received/(paid)

(4,781,000,000)

(264,000,000)

^[8]

8,337,000,000

1,315,000,000

^[10]

(834,000,000)

^[9]

(219,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(95,000,000)

(19,000,000)

Fair value of energy swap contract current liability

17,000,000

9,000,000

Fair value of energy swap contract noncurrent liability

53,000,000

97,000,000

Fair Value Inputs Level 1 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,117,000,000

861,000,000

^[1]

^[2],[3]

2,000,000

4,188,000,000

3,837,000,000

(131,000,000)

(1,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

4,057,000,000

3,836,000,000

Collateral received from counterparties, net of collateral paid to counterparties

175,000,000

Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

319,000,000

562,000,000

1,452,000,000

1,275,000,000

1,452,000,000

1,275,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,100,000,000

1,014,000,000

Debt securities issued by states of the United States and political subdivisions of the states

Residential mortgage-backed securities (non-agency)

1,100,000,000

1,014,000,000

Nuclear decommissioning trust fund investments subtotal

^[4]

2,871,000,000

2,851,000,000

Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

21,000,000

35,000,000

21,000,000

35,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

78,000,000

54,000,000

Debt securities issued by states of the United States and political subdivisions of the states

78,000,000

54,000,000

Pledged assets for Zion Station decommissioning subtotal

^[5]

99,000,000

89,000,000

Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,000,000

^[6],[7]

69,000,000

34,000,000

Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

71,000,000

36,000,000

994,000,000

Effect of netting and allocation of collateral received/(paid)

1,631,000,000

^[8]

(2,597,000,000)

^[9]

28,000,000

^[8]

Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member]

(1,225,000,000)

(1,000,000)

Effect of netting and allocation of collateral received/(paid)

(1,678,000,000)

^[8]

2,772,000,000

^[10]

(131,000,000)

^[9]

(1,000,000)

Fair Value Inputs Level 2 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

^[2],[3]

(101,000,000)

(73,000,000)

6,032,000,000

5,237,000,000

(555,000,000)

(183,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

5,477,000,000

5,054,000,000

Collateral received from counterparties, net of collateral paid to counterparties

101,000,000

73,000,000

(359,000,000)

532,000,000

Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,906,000,000

1,822,000,000

1,906,000,000

1,822,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

33,000,000

Debt securities issued by states of the United States and political subdivisions of the states

355,000,000

541,000,000

84,000,000

16,000,000

1,734,000,000

778,000,000

31,000,000

357,000,000

Residential mortgage-backed securities (non-agency)

47,000,000

83,000,000

15,000,000

5,000,000

9,000,000

47,000,000

2,275,000,000

1,860,000,000

Nuclear decommissioning trust fund investments subtotal

16,000,000

18,000,000

^[4]

4,197,000,000

3,700,000,000

Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

20,000,000

30,000,000

20,000,000

30,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

15,000,000

26,000,000

Debt securities issued by states of the United States and political subdivisions of the states

58,000,000

65,000,000

260,000,000

314,000,000

60,000,000

121,000,000

6,000,000

10,000,000

43,000,000

20,000,000

442,000,000

556,000,000

Pledged assets for Zion Station decommissioning subtotal

1,000,000

13,000,000

^[5]

463,000,000

599,000,000

Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[6],[7]

Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

857,000,000

3,872,000,000

1,653,000,000

Effect of netting and allocation of collateral received/(paid)

3,070,000,000

240,000,000

^[8]

(5,695,000,000)

(1,827,000,000)

^[9]

1,247,000,000

923,000,000

^[8]

Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

125,000,000

15,000,000

(13,000,000)

(2,814,000,000)

(1,137,000,000)

Effect of netting and allocation of collateral received/(paid)

(2,881,000,000)

(236,000,000)

^[8]

5,336,000,000

1,295,000,000

^[10]

(359,000,000)

^[9]

(91,000,000)

Fair Value Inputs Level 3 [Member]

(95,000,000)

(19,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

17,000,000

719,000,000

194,000,000

(344,000,000)

(127,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

375,000,000

67,000,000

Collateral received from counterparties, net of collateral paid to counterparties

(9,000,000)

8,000,000

Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

Residential mortgage-backed securities (non-agency)

70,000,000

13,000,000

Nuclear decommissioning trust fund investments subtotal

^[4]

70,000,000

13,000,000

Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

64,000,000

37,000,000

Pledged assets for Zion Station decommissioning subtotal

^[5]

64,000,000

37,000,000

Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[6],[7]

Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

666,000,000

124,000,000

Effect of netting and allocation of collateral received/(paid)

140,000,000

48,000,000

^[8]

(238,000,000)

(28,000,000)

^[9]

568,000,000

144,000,000

^[8]

Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

(351,000,000)

(119,000,000)

Effect of netting and allocation of collateral received/(paid)

(222,000,000)

(28,000,000)

^[8]

229,000,000

20,000,000

^[10]

(344,000,000)

^[9]

(127,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

518,000,000

466,000,000

^[11]

19,000,000

(27,000,000)

(18,000,000)

10,621,000,000

9,520,000,000

(886,000,000)

(150,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

9,735,000,000

9,370,000,000

Mark-to-market derivative liabilities (current liabilities)

27,000,000

18,000,000

504,000,000

103,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

355,000,000

29,000,000

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

319,000,000

562,000,000

1,452,000,000

1,275,000,000

1,906,000,000

1,822,000,000

3,358,000,000

3,097,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,100,000,000

1,047,000,000

Debt securities issued by states of the United States and political subdivisions of the states

355,000,000

541,000,000

84,000,000

16,000,000

1,734,000,000

778,000,000

31,000,000

357,000,000

Residential mortgage-backed securities (non-agency)

47,000,000

83,000,000

15,000,000

5,000,000

9,000,000

47,000,000

3,375,000,000

2,874,000,000

70,000,000

13,000,000

Nuclear decommissioning trust fund investments subtotal

16,000,000

18,000,000

^[12]

7,138,000,000

6,564,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

2,000,000

(57,000,000)

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

21,000,000

35,000,000

20,000,000

30,000,000

41,000,000

65,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

93,000,000

80,000,000

Debt securities issued by states of the United States and political subdivisions of the states

58,000,000

65,000,000

260,000,000

314,000,000

60,000,000

121,000,000

6,000,000

10,000,000

43,000,000

20,000,000

520,000,000

610,000,000

64,000,000

37,000,000

Pledged assets for Zion Station decommissioning subtotal

1,000,000

13,000,000

^[13]

626,000,000

725,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

5,000,000

9,000,000

Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,000,000

^[14],[15]

13,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

14,000,000

4,000,000

^[14],[15]

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

8,000,000

7,000,000

Exelon Generation Co L L C [Member] | Derivative Financial Instruments Assets [Member]

1,551,000,000

5,884,000,000

1,777,000,000

Effect of netting and allocation of collateral received/(paid)

4,841,000,000

288,000,000

^[16]

(8,530,000,000)

(1,855,000,000)

^[17]

2,195,000,000

1,761,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

111,000,000

Fair value swap contract noncurrent asset

352,000,000

503,000,000

191,000,000

Exelon Generation Co L L C [Member] | Derivative Financial Instruments Liabilities [Member]

(13,000,000)

(4,320,000,000)

(1,151,000,000)

Effect of netting and allocation of collateral received/(paid)

(4,781,000,000)

(264,000,000)

^[16]

8,337,000,000

1,315,000,000

(764,000,000)

(113,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member]

(95,000,000)

(19,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

518,000,000

466,000,000

^[11]

2,000,000

3,532,000,000

3,410,000,000

(131,000,000)

(1,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

3,401,000,000

3,409,000,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

175,000,000

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]

319,000,000

562,000,000

1,452,000,000

1,275,000,000

1,452,000,000

1,275,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

1,100,000,000

1,014,000,000

Debt securities issued by states of the United States and political subdivisions of the states

Residential mortgage-backed securities (non-agency)

1,100,000,000

1,014,000,000

Nuclear decommissioning trust fund investments subtotal

^[12]

2,871,000,000

2,851,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

21,000,000

35,000,000

21,000,000

35,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

78,000,000

54,000,000

Debt securities issued by states of the United States and political subdivisions of the states

78,000,000

54,000,000

Pledged assets for Zion Station decommissioning subtotal

^[13]

99,000,000

89,000,000

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]

1,000,000

^[14],[15]

13,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member]

14,000,000

4,000,000

^[14],[15]

994,000,000

Effect of netting and allocation of collateral received/(paid)

1,631,000,000

^[16]

(2,597,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member]

^[17]

28,000,000

(1,225,000,000)

(1,000,000)

Effect of netting and allocation of collateral received/(paid)

(1,678,000,000)

^[16]

2,772,000,000

(131,000,000)

(1,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[11]

(27,000,000)

(18,000,000)

6,018,000,000

5,222,000,000

(481,000,000)

(128,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

5,537,000,000

5,094,000,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

27,000,000

18,000,000

(359,000,000)

532,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,906,000,000

1,822,000,000

1,906,000,000

1,822,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

33,000,000

Debt securities issued by states of the United States and political subdivisions of the states

355,000,000

541,000,000

84,000,000

16,000,000

1,734,000,000

778,000,000

31,000,000

357,000,000

Residential mortgage-backed securities (non-agency)

47,000,000

83,000,000

15,000,000

5,000,000

9,000,000

47,000,000

2,275,000,000

1,860,000,000

Nuclear decommissioning trust fund investments subtotal

16,000,000

18,000,000

^[12]

4,197,000,000

3,700,000,000

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]

20,000,000

30,000,000

20,000,000

30,000,000

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

15,000,000

26,000,000

Debt securities issued by states of the United States and political subdivisions of the states

58,000,000

65,000,000

260,000,000

314,000,000

60,000,000

121,000,000

6,000,000

10,000,000

43,000,000

20,000,000

442,000,000

556,000,000

Pledged assets for Zion Station decommissioning subtotal

1,000,000

13,000,000

^[13]

463,000,000

599,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

^[14],[15]

857,000,000

3,872,000,000

1,653,000,000

Effect of netting and allocation of collateral received/(paid)

3,070,000,000

240,000,000

^[16]

(5,695,000,000)

(1,827,000,000)

^[17]

1,247,000,000

923,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

111,000,000

(13,000,000)

(2,814,000,000)

(1,137,000,000)

Effect of netting and allocation of collateral received/(paid)

(2,881,000,000)

(236,000,000)

^[16]

5,336,000,000

1,295,000,000

(359,000,000)

(91,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member]

(95,000,000)

(19,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[11]

17,000,000

1,071,000,000

888,000,000

(274,000,000)

(21,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

797,000,000

867,000,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

(9,000,000)

8,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

Residential mortgage-backed securities (non-agency)

70,000,000

13,000,000

Nuclear decommissioning trust fund investments subtotal

^[12]

70,000,000

13,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

64,000,000

37,000,000

Pledged assets for Zion Station decommissioning subtotal

^[13]

64,000,000

37,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member]

^[14],[15]

694,000,000

1,018,000,000

124,000,000

Effect of netting and allocation of collateral received/(paid)

140,000,000

48,000,000

^[16]

(238,000,000)

(28,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

^[17]

920,000,000

838,000,000

(281,000,000)

(13,000,000)

Effect of netting and allocation of collateral received/(paid)

(222,000,000)

(28,000,000)

^[16]

229,000,000

20,000,000

(274,000,000)

(21,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

173,000,000

^[18]

(9,000,000)

(8,000,000)

9,000,000

194,000,000

(431,000,000)

(808,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(422,000,000)

(614,000,000)

Mark-to-market derivative liabilities (current liabilities)

9,000,000

8,000,000

17,000,000

9,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

53,000,000

97,000,000

Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,000,000

9,000,000

19,000,000

Commonwealth Edison Co [Member] | Derivative Financial Instruments Assets [Member]

9,000,000

21,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value swap contract noncurrent asset

352,000,000

503,000,000

191,000,000

Commonwealth Edison Co [Member] | Derivative Financial Instruments Liabilities [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[2],[3]

(422,000,000)

Fair value of energy swap contract current liability

17,000,000

9,000,000

Fair value of energy swap contract noncurrent liability

53,000,000

97,000,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

173,000,000

^[18]

9,000,000

194,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

9,000,000

194,000,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,000,000

9,000,000

19,000,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member]

9,000,000

21,000,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member]

^[2],[3]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[18]

(9,000,000)

(8,000,000)

(9,000,000)

(8,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(9,000,000)

(8,000,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

9,000,000

8,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member]

^[2],[3]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[18]

(422,000,000)

(800,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(422,000,000)

(800,000,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member]

^[2],[3]

(422,000,000)

(800,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

528,000,000

175,000,000

^[19]

(18,000,000)

(21,000,000)

537,000,000

184,000,000

(18,000,000)

(21,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

519,000,000

163,000,000

PECO Energy Co [Member] | Rabbi Trust Investments [Member]

18,000,000

21,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[20],[21]

9,000,000

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

14,000,000

13,000,000

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

528,000,000

175,000,000

^[19]

537,000,000

184,000,000

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

537,000,000

184,000,000

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member]

^[20],[21]

9,000,000

(18,000,000)

(21,000,000)

(18,000,000)

(21,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(18,000,000)

(21,000,000)

18,000,000

21,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

52,000,000

33,000,000

(5,000,000)

57,000,000

33,000,000

(5,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

52,000,000

33,000,000

Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member]

5,000,000

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member]

5,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

52,000,000

33,000,000

57,000,000

33,000,000

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

57,000,000

$ 33,000,000

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member]

5,000,000

(5,000,000)

(5,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(5,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

$ 5,000,000

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[2]	The Level 3 balance includes the current and noncurrent liability of $17 million and $53 million at September 30, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[3]	The Level 3 balance includes the current and noncurrent liability of $352 million and $0 million at September 30, 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.
[4]	Excludes net assets (liabilities) of $2 million and $(57) million at September 30, 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.
[5]	Excludes net assets of $5 million and $9 million at September 30, 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.
[6]	Excludes $28 million and $25 million of the cash surrender value of life insurance investments at September 30, 2012 and December 31, 2011, respectively.
[7]	The mutual funds held by the Rabbi trusts include $54 million related to deferred compensation and $15 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.
[8]	Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $175 million, $(359) million and $(9) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 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.
[9]	The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $352 million and $0 million at September 30, 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.
[10]	The Level 3 balance includes the current and noncurrent liability of $17 million and $53 million at September 30, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[11]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[12]	Excludes net assets (liabilities) of $2 million and $(57) million at September 30, 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.
[13]	Excludes net assets of $5 million and $9 million at September 30, 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.
[14]	Excludes $8 million and $7 million of the cash surrender value of life insurance investments at September 30, 2012 and December 31, 2011, respectively.
[15]	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.
[16]	Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $175 million, $(359) million and $(9) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 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.
[17]	The Level 3 balance includes current and noncurrent assets for Generation of $352 million and $0 million at September 30, 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.
[18]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[19]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[20]	Excludes $14 million and $13 million of the cash surrender value of life insurance investments at September 30, 2012 and December 31, 2011, respectively.
[21]	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.

Fair Value of Financial Assets and Liabilities (Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation) (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

$ 1,042,000,000

(112,000,000)

$ (187,000,000)

Included in payable for Zion Station decommissioning

(139,000,000)

1,000,000

Included in noncurrent payables to affiliates

(2,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(15,000,000)

(7,000,000)

18,000,000

$ 6,000,000

437,000,000

(9,000,000)

(34,000,000)

39,000,000

$ (16,000,000)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

797,000,000

(77,000,000)

Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

425,000,000

18,000,000

67,000,000

50,000,000

$ 50,000,000

(97,000,000)

(8,000,000)

(157,000,000)

Included in payable for Zion Station decommissioning

(15,000,000)

1,000,000

(27,000,000)

1,000,000

(3,000,000)

43,000,000

(18,000,000)

38,271,210.9219556

(51,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(15,000,000)

8,000,000

(7,000,000)

15,000,000

18,000,000

^[1]

23,000,000

437,000,000

70,000,000

(10,000,000)

(9,000,000)

(22,000,000)

(34,000,000)

24,000,000

39,000,000

(16,000,000)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

375,271,210.921956

19,000,000

375,271,210.921956

19,000,000

67,000,000

(42,000,000)

(5,000,000)

(16,000,000)

18,000,000

Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]

Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member]

2,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

54,000,000

13,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

2,000,000

14,000,000

^[1]

55,000,000

6,000,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

70,000,000

6,000,000

70,000,000

6,000,000

13,000,000

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]

59,000,000

34,000,000

37,000,000

Included in payable for Zion Station decommissioning

1,000,000

(3,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

4,000,000

^[1]

17,000,000

36,000,000

60,000,000

(10,000,000)

(9,000,000)

(22,000,000)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

64,000,000

38,000,000

64,000,000

38,000,000

37,000,000

Derivative [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

295,000,000

(16,000,000)

17,000,000

50,000,000

(97,000,000)

^[2]

(8,000,000)

^[3]

(157,000,000)

^[2]

^[3]

(15,000,000)

^[4]

1,000,000

(27,000,000)

^[4]

41,000,000

^[5]

(18,000,000)

36,271,210.9219556

(51,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(15,000,000)

8,000,000

(7,000,000)

15,000,000

^[1]

329,000,000

^[1]

4,000,000

(34,000,000)

24,000,000

39,000,000

(16,000,000)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

224,271,210.921956

(25,000,000)

224,271,210.921956

(25,000,000)

17,000,000

(42,000,000)

(5,000,000)

(16,000,000)

18,000,000

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

(55,000,000)

(9,000,000)

(141,000,000)

(15,000,000)

Fair value of Constellation fair value assets acquired

323,000,000

Acquisition of marketable securities

17,000,000

Other Investments [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

17,000,000

^[1]

17,000,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

17,000,000

(25,000,000)

17,000,000

(25,000,000)

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]

810,000,000

1,030,000,000

(8,000,000)

Included in payable for Zion Station decommissioning

(110,000,000)

(311,000,000)

(343,000,000)

(3,000,000)

Included in noncurrent payables to affiliates

(2,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

8,000,000

15,000,000

23,000,000

70,000,000

(10,000,000)

(22,000,000)

24,000,000

(16,000,000)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

867,000,000

734,000,000

867,000,000

734,000,000

(5,000,000)

18,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair value of Constellation fair value assets acquired

323,000,000

Acquisition of marketable securities

17,000,000

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]

54,000,000

34,000,000

13,000,000

Included in payable for Zion Station decommissioning

(3,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

14,000,000

17,000,000

55,000,000

6,000,000

(10,000,000)

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member]

70,000,000

6,000,000

70,000,000

6,000,000

13,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

59,000,000

37,000,000

Included in payable for Zion Station decommissioning

1,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

4,000,000

36,000,000

60,000,000

(9,000,000)

(22,000,000)

Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member]

64,000,000

38,000,000

64,000,000

38,000,000

37,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

912,000,000

776,000,000

817,000,000

1,030,000,000

(112,000,000)

(8,000,000)

^[6]

(187,000,000)

^[6]

(139,000,000)

(110,000,000)

^[7]

(311,000,000)

(343,000,000)

^[7]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(15,000,000)

8,000,000

(7,000,000)

15,000,000

329,000,000

4,000,000

(34,000,000)

24,000,000

39,000,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

646,000,000

690,000,000

646,000,000

690,000,000

817,000,000

(77,000,000)

(5,000,000)

(77,000,000)

18,000,000

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

(35,000,000)

(4,000,000)

(110,000,000)

(19,000,000)

Increase (decrease) in fair value related to the swap contract

(35,000,000)

(7,000,000)

86,000,000

4,000,000

Increase (decrease) in fair value related to block contracts

(119,000,000)

(88,000,000)

(427,000,000)

(309,000,000)

(3,000,000)

Exelon Generation Co L L C [Member] | Other Investments [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

17,000,000

17,000,000

17,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Increase (decrease) in fair value related to the swap contract

7,000,000

4,000,000

Realized gains (losses) related to swap contract with unafilliated parties

88,000,000

309,000,000

(1,000,000)

(2,000,000)

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

(19,000,000)

(54,000,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Increase (decrease) in fair value related to the swap contract

(7,000,000)

4,000,000

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

(88,000,000)

(309,000,000)

(19,000,000)

(54,000,000)

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]

(617,000,000)

(788,000,000)

(800,000,000)

(971,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(195,000,000)

^[8],[9]

(76,000,000)

^[10],[11]

(378,000,000)

^[8],[9]

(259,000,000)

^[10],[11]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

(422,000,000)

(712,000,000)

(422,000,000)

(712,000,000)

(800,000,000)

Increase (decrease) in fair value related to the swap contract

35,000,000

(86,000,000)

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

119,000,000

427,000,000

$ (40,000,000)

$ 33,000,000

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]

(4,000,000)

(9,000,000)

$ (9,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

^[12]

(1,000,000)

(6,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

(3,000,000)

Increase (decrease) in fair value related to block contracts

$ 3,000,000

[1]	Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.
[2]	Includes the reclassification of $55 million and $141 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2012.
[3]	Includes the reclassification of $4 million and $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2011, respectively.
[4]	Excludes $7 million and $4 million of decreases in fair value and $88 million and $309 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd and $3 million of changes in the fair value of Generation’s block contracts with PECO for the nine months ended September 30, 2011. All items eliminate upon consolidation if Exelon’s Consolidated Financial Statements.
[5]	Excludes $35 million of decreases in fair value and $86 million of increases in fair value and $119 million and $427 million of realized losses due to settlements for the three and nine months ended September 30, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements
[6]	Includes the reclassification of $4 million and $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2011, respectively.
[7]	Includes $7 million and $4 million of decreases in fair value realized losses reclassified from OCI due to settlements of $88 million and $309 million associated with Generation's financial swap contract with ComEd for the three and nine months ended September 30, 2011, and $3 million of decreases in fair value due to settlement of Generation's block contracts with PECO for the three and nine months ended September 30, 2011. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
[8]	Includes $35 million of increases in fair value and $86 million of decreases in fair value and realized gains due to settlements of $119 million and $427 million associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2012, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
[9]	Includes $40 million and $33 million of increases in the fair value and realized losses due to settlements of $1 million and $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2012, respectively.
[10]	Includes $19 million and $54 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2011, respectively.
[11]	Includes $7 million and $4 million of increases in fair value and $88 million and $309 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the three and nine months ended September 30, 2011, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
[12]	Includes an increase of $3 million related to the settlement of PECO's block contract with Generation for the nine months ended September 30, 2011, which eliminate upon consolidation in Exelon's Consolidated Financial Statements.

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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 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	$ (106,000,000)	$ (5,000,000)	$ (195,000,000)	$ 2,000,000
Change in the unrealized gains (losses) relating to assets and liabilities held	(48,000,000)	1,000,000	(45,000,000)	22,000,000
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	9,000,000	(3,000,000)	38,000,000	(2,000,000)
Change in the unrealized gains (losses) relating to assets and liabilities held	6,000,000	(6,000,000)	29,000,000	(4,000,000)
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	(121,000,000)	(5,000,000)	(225,000,000)	2,000,000
Change in the unrealized gains (losses) relating to assets and liabilities held	(83,000,000)	1,000,000	(95,000,000)	22,000,000
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	9,000,000	(3,000,000)	38,000,000	(2,000,000)
Change in the unrealized gains (losses) relating to assets and liabilities held	$ 6,000,000	$ (6,000,000)	$ 18,000,000	$ (4,000,000)

Fair Value of Financial Assets and Liabilities (Fair Value Inputs Assets Quantitative Information) (Details) - USD ($)

9 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Derivatives Fair Value Footnotes [Abstract]

Forward Power Basis

$ 4.00

Forward Gas Basis

0.25

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member]

$ 503,000,000

Cash collateral excluded

9,000,000

Derivative Asset, Fair Value, Net

^[1],[2]

386,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Income Approach Valuation Technique [Member] | Minimum [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Income Approach Valuation Technique [Member] | Maximum [Member]

^[2]

8,000,000

Forward gas price assets

^[2]

3,040,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member]

^[2]

76,000,000

Forward gas price assets

^[2]

$ 6,350,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member]

^[2]

26.00%

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member]

^[2]

120.00%

Derivative Liability, Fair Value, Net

^[1],[2]

$ (83,000,000)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Income Approach Valuation Technique [Member] | Minimum [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Income Approach Valuation Technique [Member] | Maximum [Member]

^[2]

13,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Option Model Valuation Technique [Member] | Minimum [Member]

^[2]

$ 108,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Proprietary Trading [Member] | Option Model Valuation Technique [Member] | Maximum [Member]

^[2]

22.00%

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member]

^[2]

67.00%

Derivative Asset, Fair Value, Net

^[1],[3]

$ 352,000,000

Derivatives Fair Value Footnotes [Abstract]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Income Approach Valuation Technique [Member] | Minimum [Member]

$ 352,000,000

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Income Approach Valuation Technique [Member] | Maximum [Member]

^[3]

7.30%

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member]

^[3]

8.70%

Derivative Liability, Fair Value, Net

^[1]

$ (70,000,000)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Income Approach Valuation Technique [Member] | Minimum [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Income Approach Valuation Technique [Member] | Maximum [Member]

3.50%

Forward heat rate

^[4]

8.5

Renewable factor

80.00%

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member]

8.30%

Forward heat rate

^[4]

9.5

Renewable factor

126.00%

Derivative Liability, Fair Value, Net

^[1],[3]

$ 352,000,000

Derivatives Fair Value Footnotes [Abstract]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Income Approach Valuation Technique [Member] | Minimum [Member]

$ 352,000,000

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member] | Income Approach Valuation Technique [Member] | Maximum [Member]

^[3]

7.30%

Cost Of Capital Strategies [Abstract]

^[3]

8.70%

[1]	The fair values below do not include cash collateral held on level three positions of $9 million as of September 30, 2012
[2]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[3]	Includes current assets for Generation and current liabilities for ComEd of $352 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation.
[4]	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

Derivative Financial Instruments (Commodity Price Risk) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2012 GWH	Sep. 30, 2011 GWH	Sep. 30, 2012 GWH USD ($) MW	Sep. 30, 2011 GWH
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	4,352	1,679	9,981	4,508
Exelon Generation Co L L C [Member] \| One Year From Balance Sheet Date [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Minimum range of expected generation hedged			98.00%
Maximum range of expected generation hedged			101.00%
Exelon Generation Co L L C [Member] \| More Than One And Within Two Years From Balance Sheet Date [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Minimum range of expected generation hedged			87.00%
Maximum range of expected generation hedged			90.00%
Exelon Generation Co L L C [Member] \| More Than Two And Within Three Years From Balance Sheet Date [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Minimum range of expected generation hedged			55.00%
Maximum range of expected generation hedged			58.00%
Exelon Generation Co L L C [Member] \| More Than Three And Within Four Years From Balance Sheet Date [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Minimum range of expected generation hedged			20000000.00%
Maximum range of expected generation hedged			23000000.00%
PECO Energy Co [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged			30.00%

Derivative Financial Instruments (Interest Rate Risk) (Details)

9 Months Ended

Sep. 30, 2012

USD ($)

Sep. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

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

$ 1,551,552.635

Mark-to-market energy derivative assets (noncurrent assets)

22,000,000

103,000,000

Mark-to-market derivative liabilities (current liabilities)

125,000,000

(22,000,000)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(73,000,000)

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

(95,000,000)

30,000,000

Derivative Instruments Gain Loss Recognized In Income Net Footnotes [Abstract]

Fair value of interest rate swaps acquired from merger

5,000,000

Interest Rate Risk - Fair Value Hedges [Abstract]

Notional amounts of fair value hedges outstanding related to interest rate swaps

650,000,000

$ 100,000,000

Interest rate swaps previously held by acquiree

550,000,000

Fair value of interest rate swaps from merger acquiree

44,000,000

Notional amount of interest rate swaps acquired from merger

150,000,000

Fair value of interest rate swaps acquired from merger

5,000,000

Interest Rate Risk - Cash Flow Hedges [Abstract]

DOE interest rate swap

485,000,000

Interest Expense [Member]

407,000,000

126,000,000

Derivative Instruments Gain Loss Recognized In Income Net [Abstract]

Gain on swaps/borrowings

^[1]

(3,000,000)

$ 1,000,000

Loss on swaps/borrowings

^[1]

(6,000,000)

$ (1,000,000)

Mark-to-market energy derivative assets (noncurrent assets)

22,000,000

89,000,000

Mark-to-market derivative liabilities (current liabilities)

111,000,000

(22,000,000)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(73,000,000)

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

(95,000,000)

$ 16,000,000

Interest Rate Risk - Cash Flow Hedges [Abstract]

Percentage of interest rate swap in relation to DOE guarantee

Notional amount of interest rate swap DOE advance

$ 119,000,000

Percent of DOE loan advance offset

75.00%

Notional amount of remaining cash flow hedges

$ 365,000,000

Exelon Generation Co L L C [Member] | Antelope Valley Project [Member]

355,000,000

$ 29,000,000

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional amounts on forward starting interest rate swaps

31,000,000

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

4,000,000

Mark-to-market energy derivative assets (noncurrent assets)

42,000,000

Mark-to-market derivative liabilities (current liabilities)

42,000,000

(1,000,000)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(36,000,000)

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

(37,000,000)

5,000,000

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

Mark-to-market energy derivative assets (noncurrent assets)

^[2]

3,000,000

^[2]

10,000,000

Mark-to-market derivative liabilities (current liabilities)

^[2]

13,000,000

^[2]

(2,000,000)

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

^[2]

(2,000,000)

^[2]

11,000,000

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

Mark-to-market energy derivative assets (noncurrent assets)

^[2]

19,000,000

^[2]

37,000,000

Mark-to-market derivative liabilities (current liabilities)

^[2]

56,000,000

^[2]

(19,000,000)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

^[2]

(37,000,000)

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

^[2]

(56,000,000)

^[2]

Other Segment [Member] | Designated as Hedging Instrument [Member]

Mark-to-market energy derivative assets (noncurrent assets)

14,000,000

Mark-to-market energy derivative liabilities (noncurrent liabilities)

14,000,000

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

$ 14,000,000

[1]

For the nine months ended September 30, 2012, the loss on the swaps in the table above includes pre-tax losses of $9 million, not related to changes in benchmark interest rates and is excluded from hedge ineffectiveness.

[2]

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and 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 change in market interest rates.

Derivative Financial Instruments (Fair Value Measurments) (Details) - USD ($)

3 Months Ended

6 Months Ended

7 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

Dec. 31, 2010

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

$ 0

Net gain (loss) of reclassifications from accumulated OCI to net income related to settlements of block contracts

$ (2,000,000)

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

$ 145,000,000

$ 74,000,000

$ 548,000,000

305,000,000

Mark-to-market derivative assets with affiliate (current assets)

906,000,000

$ 906,000,000

906,000,000

432,000,000

Mark-to-market derivative assets (noncurrent assets)

937,000,000

650,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

1,843,000,000

1,082,000,000

(499,000,000)

(112,000,000)

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(335,000,000)

(107,000,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

(834,000,000)

(219,000,000)

1,009,000,000

863,000,000

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Other Derivatives Not Designated As Hedging Instruments [Abstract]

503,000,000

(91,000,000)

22,000,000

98,000,000

13,000,000

123,000,000

(101,000,000)

216,000,000

(372,000,000)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

32,000,000

(79,000,000)

314,000,000

(359,000,000)

Pro Forma [Member]

22,000,000

13,000,000

(101,000,000)

(372,000,000)

Operating Revenue [Member]

(79,000,000)

(359,000,000)

Proprietary Trading Activities [Abstract]

(2,000,000)

2,000,000

12,000,000

22,000,000

25,000,000

(6,000,000)

57,000,000

(19,000,000)

Total Cash Flow Hedges [Member]

23,000,000

(4,000,000)

69,000,000

3,000,000

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Accumulated OCI derivative gain - Beginning Balance

547,000,000

209,000,000

$ 488,000,000

$ 400,000,000

488,000,000

400,000,000

Effective portion of changes in fair value

(26,000,000)

300,500,000

^[1]

(73,000,000)

Accumulated OCI derivative gain - Ending Balance

459,000,000

145,000,000

547,000,000

209,000,000

459,000,000

145,000,000

488,000,000

$ 400,000,000

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gain (loss) related to effective portion of changes in fair value of treasury rate locks

(23,000,000)

Total Cash Flow Hedges [Member] | Operating Revenue [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(88,000,000)

(45,000,000)

(332,000,000)

(184,000,000)

Total Cash Flow Hedges [Member] | Purchased Power [Member]

2,500,000

2,000,000

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

7,000,000

Cash Flow Hedge Activity Impact [Abstract]

Net unrealized pre-tax gain (loss) on effective cash flow hedges

1,928,000,000

Net unrealized pre-tax gain (loss) on effective cash flow hedges related to swap contract

693,000,000

Expected reclassification from accumulated other comprehensive income to results of operations related to fair value of swap contracts

383,000,000

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

283,000,000

162,000,000

1,005,000,000

617,000,000

Mark-to-market derivative assets with affiliate (current assets)

906,000,000

^[2]

906,000,000

^[2]

906,000,000

^[2]

432,000,000

^[3]

352,000,000

^[2]

352,000,000

^[2]

352,000,000

^[2]

503,000,000

^[3]

Mark-to-market derivative assets (noncurrent assets)

937,000,000

^[2]

937,000,000

^[2]

937,000,000

^[2]

635,000,000

^[3]

Mark-to-market derivative assets with affiliate (noncurrent assets)

191,000,000

^[3]

Mark-to-market derivative liabilities (current liabilities)

2,195,000,000

^[2]

2,195,000,000

^[2]

2,195,000,000

^[2]

1,761,000,000

^[3]

(482,000,000)

^[2]

(482,000,000)

^[2]

(482,000,000)

^[2]

(103,000,000)

^[3]

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(282,000,000)

^[2]

(282,000,000)

^[2]

(282,000,000)

^[2]

(10,000,000)

^[3]

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

(764,000,000)

^[2]

(764,000,000)

^[2]

(764,000,000)

^[2]

(113,000,000)

^[3]

1,431,000,000

^[2]

1,431,000,000

^[2]

1,431,000,000

^[2]

1,648,000,000

^[3]

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(126,000,000)

22,000,000

36,000,000

13,000,000

142,000,000

(101,000,000)

245,000,000

(372,000,000)

Exelon Generation Co L L C [Member] | Pro Forma [Member]

16,000,000

(79,000,000)

281,000,000

(359,000,000)

^[4]

Other Derivatives Not Designated As Hedging Instruments [Abstract]

22,000,000

13,000,000

(101,000,000)

(372,000,000)

Exelon Generation Co L L C [Member] | Operating Revenue [Member]

(79,000,000)

(359,000,000)

Proprietary Trading Activities [Abstract]

(2,000,000)

2,000,000

12,000,000

22,000,000

25,000,000

(6,000,000)

57,000,000

(19,000,000)

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

23,000,000

(4,000,000)

69,000,000

3,000,000

Mark-to-market derivative assets with affiliate (current assets)

3,399,000,000

^[5]

3,399,000,000

^[5]

3,399,000,000

^[5]

1,195,000,000

352,000,000

^[5]

352,000,000

^[5]

352,000,000

^[5]

Mark-to-market derivative assets (noncurrent assets)

2,133,000,000

^[5]

2,133,000,000

^[5]

2,133,000,000

^[5]

582,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

5,884,000,000

^[5]

5,884,000,000

^[5]

5,884,000,000

^[5]

1,777,000,000

(2,951,000,000)

^[5]

(2,951,000,000)

^[5]

(2,951,000,000)

^[5]

(965,000,000)

Mark-to-market derivative liability with affiliate (current liability)

^[5]

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(1,369,000,000)

^[5]

(1,369,000,000)

^[5]

(1,369,000,000)

^[5]

(186,000,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

(4,320,000,000)

^[5]

(4,320,000,000)

^[5]

(4,320,000,000)

^[5]

(1,151,000,000)

1,564,000,000

^[5]

1,564,000,000

^[5]

1,564,000,000

^[5]

626,000,000

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

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Current assets collateral offset

92,000,000

338,000,000

Noncurrent assets collateral offset

263,000,000

187,000,000

Current liabilities collateral offset

(49,000,000)

15,000,000

Noncurrent liabilities collateral offset

(113,000,000)

Total cash collateral received net of cash collateral posted

540,000,000

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

Mark-to-market derivative assets with affiliate (current assets)

^[6]

438,000,000

^[6]

503,000,000

Mark-to-market derivative assets (noncurrent assets)

^[6]

419,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

^[6]

191,000,000

Mark-to-market derivative liabilities (current liabilities)

^[6]

1,551,000,000

^[6]

(9,000,000)

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

^[6]

(4,000,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

^[6]

(13,000,000)

^[6]

1,538,000,000

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract noncurrent asset

352,000,000

503,000,000

191,000,000

Noncurrent liability DOE interest rate swap

19,000,000

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

Mark-to-market derivative assets with affiliate (current assets)

3,694,000,000

217,000,000

Mark-to-market derivative assets (noncurrent assets)

1,147,000,000

71,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

4,841,000,000

288,000,000

(3,675,000,000)

(194,000,000)

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(1,106,000,000)

(70,000,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

(4,781,000,000)

(264,000,000)

60,000,000

24,000,000

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

Mark-to-market derivative assets with affiliate (current assets)

(6,187,000,000)

^[7]

(6,187,000,000)

^[7]

(6,187,000,000)

^[7]

(1,418,000,000)

^[8]

Mark-to-market derivative assets (noncurrent assets)

(2,343,000,000)

^[7]

(2,343,000,000)

^[7]

(2,343,000,000)

^[7]

(437,000,000)

^[8]

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(8,530,000,000)

^[7]

(8,530,000,000)

^[7]

(8,530,000,000)

^[7]

(1,855,000,000)

^[8]

6,144,000,000

^[7]

6,144,000,000

^[7]

6,144,000,000

^[7]

1,065,000,000

^[8]

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

2,193,000,000

^[7]

2,193,000,000

^[7]

2,193,000,000

^[7]

250,000,000

^[8]

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

8,337,000,000

^[7]

8,337,000,000

^[7]

8,337,000,000

^[7]

1,315,000,000

^[8]

(193,000,000)

^[7]

(193,000,000)

^[7]

(193,000,000)

^[7]

(540,000,000)

^[8]

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Total cash collateral received net of cash collateral posted

193,000,000

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

923,000,000

^[9],[10]

688,000,000

^[11]

925,000,000

^[12],[13]

1,011,000,000

^[14]

925,000,000

^[12],[13]

1,011,000,000

^[14]

1,011,000,000

^[14]

Effective portion of changes in fair value

^[15]

(26,000,000)

^[16]

432,000,000

^[17]

(69,000,000)

^[18]

Accumulated OCI derivative gain - Ending Balance

752,000,000

^[12],[13]

571,000,000

^[14],[19]

923,000,000

^[9],[10]

688,000,000

^[11]

752,000,000

^[12],[13]

752,000,000

^[12],[13]

571,000,000

^[14],[19]

925,000,000

^[12],[13]

1,011,000,000

^[14]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Unrealized gain (loss) related to fair value of swap contract

232,000,000

400,000,000

315,000,000

458,000,000

232,000,000

400,000,000

589,000,000

Unrealized gain (loss) related to fair value of block contract

1,000,000

2,000,000

1,000,000

3,000,000

Net gain (loss) related to effective portion of changes in fair value of swap contract

88,000,000

232,000,000

420,000,000

(5,000,000)

Net gains (losses) related to interest rate swaps and treasury rate locks

(22,000,000)

(6,000,000)

$ 22,000,000

$ 2,000,000

(22,000,000)

$ (10,000,000)

Net gain (loss) related to effective portion of changes in fair value of treasury rate locks

(2,000,000)

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

(171,000,000)

^[20]

(98,000,000)

^[21]

(608,000,000)

^[22]

(373,000,000)

^[23]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

7,000,000

3,000,000

2,000,000

Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract

(83,000,000)

(53,000,000)

(276,000,000)

$ (187,000,000)

Net gain (loss) of reclassifications from accumulated OCI to net income related to settlements of block contracts

$ (1,000,000)

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Purchased Power [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Mark-to-market derivative liability with affiliate (current liability)

(352,000,000)

(503,000,000)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

(191,000,000)

Commonwealth Edison Co [Member] | Derivative [Member]

Mark-to-market derivative assets with affiliate (current assets)

^[5]

^[5]

Mark-to-market derivative assets (noncurrent assets)

^[5]

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

^[5]

(17,000,000)

^[24]

(17,000,000)

^[24]

(17,000,000)

^[24]

(9,000,000)

^[25]

Mark-to-market derivative liability with affiliate (current liability)

(352,000,000)

^[5]

(352,000,000)

^[5]

(352,000,000)

^[5]

(503,000,000)

^[6]

Mark-to-market energy derivative liabilities (noncurrent liabilities)

(53,000,000)

^[24]

(53,000,000)

^[24]

(53,000,000)

^[24]

(97,000,000)

^[25]

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

^[6]

(191,000,000)

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

(422,000,000)

^[5],[24]

(422,000,000)

^[5],[24]

(422,000,000)

^[5],[24]

(800,000,000)

^[6],[25]

(422,000,000)

^[5],[24]

(422,000,000)

^[5],[24]

(422,000,000)

^[5],[24]

(800,000,000)

^[6],[25]

Commonwealth Edison Co [Member] | Cash Flow Hedging [Member]

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract noncurrent liability

352,000,000

191,000,000

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liability with affiliate (current liability)

Other Segment [Member]

Other Segment [Member] | Derivative [Member]

^[5]

Mark-to-market derivative assets with affiliate (current assets)

Mark-to-market derivative assets (noncurrent assets)

15,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

15,000,000

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market energy derivative liabilities (noncurrent liabilities)

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

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

15,000,000

Other Segment [Member] | Business Intersegment Eliminations [Member]

Mark-to-market derivative assets with affiliate (current assets)

(352,000,000)

^[5]

(352,000,000)

^[5]

(352,000,000)

^[5]

(503,000,000)

^[6]

Mark-to-market derivative assets (noncurrent assets)

^[5]

Mark-to-market derivative assets with affiliate (noncurrent assets)

^[6]

(191,000,000)

Mark-to-market derivative liabilities (current liabilities)

(352,000,000)

^[5]

(352,000,000)

^[5]

(352,000,000)

^[5]

(694,000,000)

^[6]

^[5]

Mark-to-market derivative liability with affiliate (current liability)

352,000,000

^[5]

352,000,000

^[5]

352,000,000

^[5]

503,000,000

^[6]

Mark-to-market energy derivative liabilities (noncurrent liabilities)

^[5]

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

^[6]

191,000,000

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

352,000,000

^[5]

352,000,000

^[5]

352,000,000

^[5]

694,000,000

^[6]

$ 0

^[5]

$ 0

^[5]

$ 0

^[5]

$ 0

[1]	Includes $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.
[2]	Current and noncurrent assets are shown net of collateral of $92 million and $263 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(49) million and $(113) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $193 million at September 30, 2012.
[3]	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.
[4]	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
[5]	Includes current assets for Generation and current liabilities for ComEd of $352 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.
[6]	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 noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above.
[7]	Represents the netting of fair value balances with the same counterparty and the application of collateral.
[8]	Represents the netting of fair value balances with the same counterparty and the application of collateral.
[9]	Excludes $22 million of losses and $22 million of losses net of taxes, related to interest rate swaps and treasury rate locks for the three months ended September 30, 2012 and three months ended June 30, 2012.
[10]	Includes $232 million and $315 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and June 30, 2012, respectively.
[11]	Includes $400 million and $458 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2011 and June 30, 2011, respectively.
[12]	Excludes $22 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury locks for the nine months ended September 30, 2012 and year ended December 31, 2011, respectively.
[13]	Includes $232 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of September 30, 2012 and December 31, 2011.
[14]	Includes $400 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2011 and December 31, 2010, respectively.
[15]	Includes $0 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.
[16]	Includes a $5 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended September 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in fair value of the block contracts with PECO for the three months ended September 30, 2011 as the mark-to-market balances previously recorded will be amortized over the term of the contract.
[17]	Includes $88 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 through the date of de-designation prior to the merger.
[18]	Includes a $2 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the nine months ended September 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO's block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.
[19]	Excludes $6 million loss and $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2011 and December 31, 2010.
[20]	Includes $83 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.
[21]	Includes a $53 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended September 30, 2011.
[22]	Includes $276 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd
[23]	Includes a $187 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the nine months ended September 30, 2011
[24]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[25]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative Financial Instruments (Credit Risk) (Details)	Sep. 30, 2012 USD ($)
Exelon Generation Co L L C [Member]
Credit Risk [Abstract]
Financial institutions	$ 386,000,000
Investor-owned utilities, marketers and power producers	902,000,000
Energy cooperative and municipalities	710,000,000
Other	72,000,000
Total	2,070,000,000
Due From Related Parties [Abstract]
Net receivable from electric utility	53,000,000
Net receivable from affiliated electric and gas utility	53,000,000
Exelon Generation Co L L C [Member] \| Total Exposure Before Credit Collateral [Member]
Credit Risk [Abstract]
Investment grade	1,968,000,000
Non-investment grade	46,000,000
No external ratings - internally rated - investment grade	501,000,000
No external ratings - internally rated - non-investment grade	90,000,000
Total	2,605,000,000
Exelon Generation Co L L C [Member] \| Credit Collateral [Member]
Credit Risk [Abstract]
Investment grade	492,000,000
Non-investment grade	25,000,000
No external ratings - internally rated - investment grade	16,000,000
No external ratings - internally rated - non-investment grade	2,000,000
Total	535,000,000
Exelon Generation Co L L C [Member] \| Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	1,476,000,000
Non-investment grade	21,000,000
No external ratings - internally rated - investment grade	485,000,000
No external ratings - internally rated - non-investment grade	88,000,000
Total	2,070,000,000
Exelon Generation Co L L C [Member] \| Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	0
Non-investment grade	0
No external ratings - internally rated - investment grade	1,000,000
No external ratings - internally rated - non-investment grade	0
Total	1,000,000
Exelon Generation Co L L C [Member] \| Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	0
Non-investment grade	0
No external ratings - internally rated - investment grade	267,000,000
No external ratings - internally rated - non-investment grade	0
Total	267,000,000
PECO Energy Co [Member]
Natural Gas Supply And Management Agreement Credit Exposure [Abstract]
Natural gas asset manager parental guarantee	14,000,000
Credit exposure under natural gas supply and management agreements	8,000,000
Baltimore Gas and Electric Company [Member]
Due From Related Parties [Abstract]
Net receivable from affiliated electric and gas utility	11,000,000
Natural Gas Supply And Management Agreement Credit Exposure [Abstract]
Credit exposure under off system sales	$ 1,000,000

Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) - USD ($)

Sep. 30, 2012

Dec. 31, 2011

Collateral And Contingent Related Features [Abstract]

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

^[1]

$ (2,720,000,000)

$ (1,014,000,000)

Contractual right of offset related to derivative assets

^[2]

2,156,000,000

928,000,000

Net liability position after contractual right of offset

^[3]

(564,000,000)

(86,000,000)

Collateral And Contingent Related Features [Abstract]

Incremental collateral for loss of investment grade credit rating

2,004,000,000

1,612,000,000

Cash collateral held

607,000,000

542,000,000

Cash collateral posted

415,000,000

Letters of credit held

109,000,000

89,000,000

Letters of credit posted

973,000,000

Swap Contract Collateral Posting Limit [Abstract]

Fair value of interest-rate swap in asset position

Master Netting Arrangements [Abstract]

Cash collateral received not offset against net derivative positions

1,000,000

$ 2,000,000

Collateral And Contingent Related Features [Abstract]

Incremental collateral for loss of investment grade credit rating

30,000,000

Collateral And Contingent Related Features [Abstract]

Incremental collateral for loss of investment grade credit rating

$ 51,000,000

[1]	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.
[2]	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
[3]	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Debt and Credit Agreements (Details)

3 Months Ended

9 Months Ended

Sep. 30, 2012

USD ($)

BasisPoints

Sep. 30, 2012

USD ($)

BasisPoints

Aug. 10, 2012

USD ($)

Jul. 18, 2012

USD ($)

Jul. 13, 2012

USD ($)

Jun. 28, 2012

USD ($)

Jun. 18, 2012

USD ($)

Dec. 31, 2011

USD ($)

Sep. 30, 2011

USD ($)

Basis points adders for prime-based borrowings | BasisPoints

0.0065

Basis points adders for LIBOR-based borrowings | BasisPoints

0.0165

Previous Aggregate Commitments Of Acquired Entity

$ 2,500,000,000

Amended Aggregate Commitments Of Acquired Entity

1,500,000,000

Accounts Receivable Agreement [Abstract]

$ 500,000,000

Revolver Under Amendment

$ 1,500,000,000

Short-term notes payable - accounts receivable agreement

225,000,000

$ 225,000,000

Gross accounts receivable pledged as collateral

314,000,000

$ 314,000,000

329,000,000

AVSR Project Development Debt Agreement [Abstract]

Basis point spread on DOE loan advance | BasisPoints

0.00375

DOE interest rate swap

$ 485,000,000

17,050,000,000

11,799,000,000

Increase in fair value adjustment

649,000,000

390,000,000

403,000,000

Fair Value Adjustment Outstanding

212,000,000

Aggregate bank commitments under unsecured revolving credit facilities

9,800,000,000

Footnotes To Line Of Credit Facility [Abstract]

Credit facility agreements with minority and community banks

118,000,000

Series A Junior Subordinated Debentures, 8.625% Due 2063 [Member]

$ 450,000,000

8.625%

Senior Notes [Member]

Senior Notes [Member] | Senior Notes, 7.6% Due 2032 [Member]

$ 700,000,000

Long Term Debt Retirements [Member] | Medium Term Notes, 7.3% June 1,2012 [Member]

Long term debt old notes

$ 258,000,000

$ 2,000,000

Long Term Debt Retirements [Member] | Senior Notes [Member] | Senior Notes, 7.6% Due 2032 [Member]

7.30%

$ 442,000,000

Syndicated Revolver [Member]

7.60%

Aggregate bank commitments under unsecured revolving credit facilities

$ 2,000,000,000

Exelon Corporate [Member]

Additional amounts available upon request under current credit facilities

$ 250,000,000

Basis points adders for prime-based borrowings | BasisPoints

0.00275

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01275

$ 200,000,000

Exelon Corporate [Member] | Commercial Paper [Member]

200,000,000

Exelon Corporate [Member] | Long Term Debt Assumed [Member] | Senior Notes [Member]

$ 15,000,000

161,000,000

Exelon Corporate [Member] | Long Term Debt Assumed [Member] | Senior Notes [Member] | Fixed Rate Debt [Member]

5.15%

$ 550,000,000

Exelon Corporate [Member] | Long Term Debt Exchange Offer Purchased [Member]

4.55%

Long term debt old notes

$ 608,000,000

Additional amounts available upon request under current credit facilities

$ 1,000,000,000

Basis points adders for prime-based borrowings | BasisPoints

0.00075

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01075

$ 3,500,000,000

AVSR Project Development Debt Agreement [Abstract]

5,300,000,000

DOE advances received

69,000,000

DOE Interest Rate Swap Loan Advance

100,000,000

Generation letters of credit outstanding to support project

656,000,000

7,148,000,000

3,674,000,000

Footnotes To Line Of Credit Facility [Abstract]

3,500,000,000

Credit facility agreements with minority and community banks

$ 50,000,000

50,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Senior Notes, 7.6% Due 2032 [Member]

Exelon Generation Co L L C [Member] | DOE Financing Project [Member]

7.60%

Minimum interest rate on long-term debt

2.482%

Maximum interest rate on long-term debt

2.595%

DOE Advances received, $59 Million, October 1, 2012

$ 59,000,000

DOE Advances received, $2 Million, October 31, 2012

2,000,000

Exelon Generation Co L L C [Member] | Commercial Paper [Member]

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | CEU Credit Agreement [Member]

$ 43,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Clean Horizons [Member]

1.99%

$ 38,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Senior Notes [Member] | Senior Notes, 4.25% June 15, 2022 [Member]

2.50%

4.25%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Senior Notes [Member] | Senior Notes, 5.6% June 15, 2042 [Member]

$ 523,000,000

5.60%

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

$ 788,000,000

Minimum interest rate on long-term debt

100,000,000

$ 100,000,000

2.33%

Maximum interest rate on long-term debt

3.092%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member]

$ 2,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Armstrong Co Tax Exempt, 5% December 1,2042 [Member]

7.83%

$ 46,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | CEU Credit Agreement [Member]

5.00%

$ 3,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | MEDCO Tax-Exempt Bonds [Member]

2.27%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Solar Revolver [Member]

$ 75,000,000

$ 13,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Issued And Sold [Member] | Senior Notes [Member]

2.49%

Footnotes To Long-Term Debt [Abstract]

775,000,000

Notional amount of interest rate cash flow hedge derivatives

470,000,000

Loss on interest rate swap

$ 7,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Purchased [Member]

Increase in fair value adjustment

$ 1,000,000

$ 441,000,000

$ 13,000,000

Exelon Generation Co L L C [Member] | Long Term Debt Exchange Offer Exchanged [Member] | Senior Notes [Member]

Cash payment related to exchange offer

535,000,000

$ 60,000,000

Exelon Generation Co L L C [Member] | Syndicated Revolver [Member]

Aggregate bank commitments under unsecured revolving credit facilities

$ 5,300,000,000

5,300,000,000

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

Aggregate bank commitments under unsecured revolving credit facilities

300,000,000

Additional amounts available upon request under current credit facilities

$ 500,000,000

Basis Points For Cash Borrowings | BasisPoints

0.0035

Amount Of Aggregate Letters of Credit Available

$ 500,000,000

4,965,000,000

5,215,000,000

Footnotes To Line Of Credit Facility [Abstract]

206,000,000

Credit facility agreements with minority and community banks

34,000,000

Commonwealth Edison Co [Member] | Commercial Paper [Member]

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds, 1.625% January 15, 2014 [Member]

35,000,000

$ 600,000,000

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds, 3.800% October 1, 2042 [Member]

1.625%

$ 350,000,000

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds, 1.950% September 1, 2016 [Member]

3.80%

^[1],[2]

$ 250,000,000

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds, 3.400% September 1, 2021 [Member]

^[1],[2]

1.95%

^[1],[2]

$ 350,000,000

Commonwealth Edison Co [Member] | Long Term Debt Retirements [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds, 6.15% March 15, 2012 [Member]

^[1],[2]

3.40%

$ 450,000,000

Commonwealth Edison Co [Member] | Long Term Debt Retirements [Member] | Sinking Fund Debentures [Member]

6.15%

$ 1,000,000

Commonwealth Edison Co [Member] | Proceeds From Issuance Of Debt [Member] | First Mortgage Bonds [Member]

4.75%

Commonwealth Edison Co [Member] | Syndicated Revolver [Member]

536000000.00%

Aggregate bank commitments under unsecured revolving credit facilities

$ 1,000,000,000

Additional amounts available upon request under current credit facilities

$ 250,000,000

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01

$ 300,000,000

Accounts Receivable Agreement [Abstract]

600,000,000

Short-term notes payable - accounts receivable agreement

225,000,000

Gross accounts receivable pledged as collateral

314,000,000

329,000,000

1,947,000,000

1,597,000,000

184,000,000

Footnotes To Line Of Credit Facility [Abstract]

300,000,000

Credit facility agreements with minority and community banks

34,000,000

PECO Energy Co [Member] | Commercial Paper [Member]

PECO Energy Co [Member] | Long Term Debt Issuances [Member] | First And Refunding Mortgage Bonds, 2.375% September 15, 2022 [Member]

$ 350,000,000

PECO Energy Co [Member] | Long Term Debt Retirements [Member] | First and Refunding Mortgage Bonds 4.750% October 1, 2012 [Member]

2.375%

PECO Energy Co [Member] | Syndicated Revolver [Member]

4.75%

Aggregate bank commitments under unsecured revolving credit facilities

$ 600,000,000

Additional amounts available upon request under current credit facilities

$ 100,000,000

Basis points adders for prime-based borrowings | BasisPoints

0.00075

Basis points adders for LIBOR-based borrowings | BasisPoints

0.01075

$ 600,000,000

$ 600,000,000

1,446,000,000

1,596,000,000

258,000,000

$ 258,000,000

Footnotes To Line Of Credit Facility [Abstract]

600,000,000

Credit facility agreements with minority and community banks

5,000,000

Baltimore Gas and Electric Company [Member] | Long Term Debt Issuances [Member] | Ten Year Notes [Member]

$ 250,000,000

Baltimore Gas and Electric Company [Member] | Long Term Debt Retirements [Member] | Rate Stabilization Bonds, 5.68% April 1, 2017 [Member]

2.80%

$ 31,000,000

Baltimore Gas and Electric Company [Member] | Long Term Debt Retirements [Member] | Medium Term, Notes 6.73% 6.75% June 15, 2012 [Member]

5.68%

Minimum interest rate on long-term debt

$ 110,000,000

6.73%

Maximum interest rate on long-term debt

6.75%

Baltimore Gas and Electric Company [Member] | Long Term Debt Retirements [Member] | Fixed Rate Debt [Member] | Rate Stabilization Bonds, 5.68% April 1, 2017 [Member]

Baltimore Gas and Electric Company [Member] | Syndicated Revolver [Member]

32,000,000

$ 32,000,000

Aggregate bank commitments under unsecured revolving credit facilities

$ 600,000,000

[1]	As of September 30, 2011, $536 million of the total proceeds from the issuances of First Mortgage Bonds due September 1, 2016 and September 1, 2021 was reflected in restricted cash on Exelon’s and ComEd’s Consolidated Balance Sheets for the purpose of redeeming outstanding debt under ComEd’s long-term debt refinancing authority with the ICC.
[2]	To be used to refinance the outstanding principal amount of three series of variable rate tax-exempt bonds, to refinance the outstanding principal of First Mortgage 5.40% Bonds due December 15, 2011.

Income Taxes (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2010

35.00%

^[1]

35.00%

^[1]

35.00%

State income taxes, net of Federal income tax benefit

5.60%

^[1]

4.80%

(4.70%)

^[1]

4.10%

Qualified nuclear decommissioning trust fund income (losses)

7.80%

^[1]

(6.40%)

6.90%

^[1]

(0.60%)

0.30%

^[1]

1.00%

0.00%

^[1]

(0.40%)

(0.20%)

^[1]

(0.10%)

(0.30%)

^[1]

(0.10%)

0.00%

0.00%

^[1]

0.20%

^[1]

0.00%

(4.80%)

^[1]

(0.30%)

(2.30%)

^[1]

(0.30%)

(4.70%)

^[1]

(3.20%)

(2.20%)

^[1]

(1.00%)

(2.50%)

^[1]

(1.10%)

(2.60%)

^[1]

(1.00%)

^[1]

(0.10%)

3.80%

^[1]

0.00%

^[2]

3.60%

(1.20%)

^[1],[3]

0.10%

(1.30%)

^[1]

(0.30%)

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

35.20%

^[1]

29.80%

36.10%

^[1]

35.40%

Tax positions for which there is uncertainty about the timing of tax benefits

$ 980,000,000

Tax Method of Accounting for Repairs [Abstract]

Repair cost tax benefit

19,000,000

1999 Sale of Fossil Generating Assets [Abstract]

Deferred tax gain on sale of fossil generating assets

2,800,000,000

Deferred tax gain under involuntary conversion provisions of the IRC

1,600,000,000

Deferred tax gain under like-kind exchange provisions of the IRC

1,200,000,000

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

870,000,000

Potential interest expense from a successful IRS challenge of the like-kind exchange position

260,000,000

IRS withdrawn penalties originally asserted for understatement of tax related to involuntary conversion

110,000,000

IRS asserted penalties for understatement of tax related to like-kind exchange

86,000,000

Tax and interest to be assessed under preliminary settlement with IRS within the next 12 months

300,000,000

Refund due from the settlement of the 2001 tax method of accounting change for certain overhead costs under SSCM

300,000,000

Payment to IRS for open tax positions

$ 302,000,000

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

72,000,000

Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes

116,000,000

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

44,000,000

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 161,000,000

$ 255,000,000

$ 445,000,000

$ 1,034,000,000

35.00%

^[1]

35.00%

^[1]

35.00%

State income taxes, net of Federal income tax benefit

5.90%

^[1]

5.50%

2.50%

^[1]

4.90%

Qualified nuclear decommissioning trust fund income (losses)

21.50%

^[1]

(10.20%)

10.90%

^[1]

(0.80%)

0.80%

^[1]

1.70%

0.00%

^[1]

(0.60%)

(0.50%)

^[1]

(0.20%)

(0.50%)

^[1]

(0.20%)

0.00%

0.00%

^[1]

0.00%

^[1]

0.00%

(13.00%)

^[1]

(0.20%)

(3.30%)

^[1]

(0.20%)

0.00%

^[1]

0.00%

^[1]

0.00%

(7.40%)

^[1]

(1.70%)

(4.30%)

^[1]

(1.40%)

^[1]

0.00%

6.00%

^[1]

0.00%

^[2]

0.00%

7.10%

^[1],[3]

0.30%

0.80%

^[1]

(0.90%)

Effective Income Tax Rate Impact [Abstract]

49.40%

^[1]

30.20%

47.10%

^[1]

35.80%

Effective tax rate impact due to uncertain Federal tax positions

(5.30%)

Effective tax rate impact due to finalization of PY tax return calculations

4.20%

Effective tax rate impact due to changes in forecasted activity

4.10%

Effective tax rate impact due to other

4.10%

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

Tax positions for which there is uncertainty about the timing of tax benefits

$ 829,000,000

Refunds expected to be received (paid) as a result of preliminary settlement with IRS

(10,000,000)

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes

14,000,000

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

14,000,000

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 85,000,000

$ 167,000,000

$ 373,000,000

$ 738,000,000

35.00%

State income taxes, net of Federal income tax benefit

5.00%

0.80%

5.40%

3.40%

Qualified nuclear decommissioning trust fund income (losses)

0.00%

0.00%

(0.00%)

0.30%

0.60%

(1.50%)

(0.50%)

(0.40%)

(0.50%)

(0.70%)

(0.20%)

(0.40%)

(0.00%)

0.00%

0.00%

^[2]

0.00%

0.00%

^[3]

0.40%

0.20%

0.30%

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

39.60%

35.30%

40.50%

36.40%

Tax positions for which there is uncertainty about the timing of tax benefits

$ 68,000,000

1999 Sale of Fossil Generating Assets [Abstract]

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

510,000,000

Potential interest expense from a successful IRS challenge of the like-kind exchange position

160,000,000

Refunds expected to be received (paid) as a result of preliminary settlement with IRS

(405,000,000)

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 59,000,000

$ 61,000,000

$ 149,000,000

$ 169,000,000

35.00%

State income taxes, net of Federal income tax benefit

3.00%

2.90%

3.20%

(0.40%)

Qualified nuclear decommissioning trust fund income (losses)

0.00%

0.00%

(0.00%)

0.00%

0.00%

(0.30%)

(21.00%)

(23.80%)

(9.70%)

(6.80%)

(0.00%)

0.00%

0.00%

^[2]

0.00%

0.20%

^[3]

0.10%

0.00%

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

16.90%

13.90%

28.20%

27.50%

Tax positions for which there is uncertainty about the timing of tax benefits

$ 44,000,000

Tax Method of Accounting for Repairs [Abstract]

Repair cost tax benefit

22,000,000

Refunds expected to be received (paid) as a result of preliminary settlement with IRS

135,000,000

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 25,000,000

$ 17,000,000

$ 118,000,000

$ 119,000,000

^[4]

0.00%

35.00%

State income taxes, net of Federal income tax benefit

^[4]

0.00%

6.20%

2.30%

4.80%

Qualified nuclear decommissioning trust fund income (losses)

^[4]

0.00%

^[4]

0.00%

^[4]

(0.00%)

^[4]

0.00%

(16.40%)

(4.60%)

(0.80%)

^[4]

0.00%

13.80%

2.90%

(0.50%)

^[4]

0.00%

48.40%

7.20%

(1.60%)

^[4]

(0.00%)

FIN 48

^[4]

137.80%

(1.10%)

^[5]

^[4]

0.00%

^[2],[4]

0.00%

(14.00%)

^[4]

0.00%

^[3]

75.20%

4.50%

(0.10%)

Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract]

^[4]

0.00%

300.00%

33.30%

35.70%

Tax positions for which there is uncertainty about the timing of tax benefits

$ 0

Interest recognized related to uncertain tax positions [Abstract]

Net interest (income) expense recognized related to uncertain tax positions

2,000,000

9,000,000

Income Tax Expense Benefit Continuing Operations [Line Items]

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

$ 0

$ (3,000,000)

$ (7,000,000)

$ 55,000,000

[1]	Exelon activity for the three and nine months ended September 30, 2012 includes the results of Constellation and BGE for March 12, 2012 - September 30, 2012. Generation activity for the three and nine months ended September 30, 2012 includes the results of Constellation for March 12, 2012 - September 30, 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]	For the three months ended September 31, 2012, Generation’s effective tax rate was affected by the resolution of uncertain Federal tax positions (5.3%), the finalization of prior year tax return calculations 4.2%, changes in the forecasted activity attributable to noncontrolling interests 4.1%, and other 4.1%.
[4]	BGE activity represents the activity for the three and nine months ended September 30, 2012 and 2011. BGE activity for the three months ended September 30, 2012 resulted in zero pre-tax income and zero income taxes. BGE recognized a loss before income taxes for the nine months ended September 30, 2012 and three months ended September 30, 2011. As a result, positive percentages represent an income tax benefit for BGE for the nine months ended September 30, 2012 and three months ended September 30, 2011.
[5]	Until March 12, 2012, BGE recorded interest and penalties relating to unrecognized tax benefits as tax expense.

Asset Retirement Obligation (Details) - USD ($)

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Feb. 29, 2012

Dec. 31, 2011

Net increase (decrease) due to changes in estimated future cash flows

$ 749,000,000

Increase in estimated cash flows associated with Zion Station decommissioning

$ 28,000,000

10,000,000

78,000,000

631,000,000

$ 734,000,000

582,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

160,000,000

128,000,000

7,140,000,000

6,507,000,000

Nuclear Decommissioning Asset Retirement Obligation Rollforward [Abstract]

$ 115,000,000

^[1]

3,680,000,000

Net increase (decrease) due to changes in estimated future cash flows

169,000,000

749,000,000

(2,000,000)

Footnotes To Nuclear Decommissioning Asset Retirement Obligation [Abstract]

^[1]

4,596,000,000

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

6,000,000

5,000,000

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[2]

202,000,000

$ (363,000,000)

352,000,000

$ (223,000,000)

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[3],[4]

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

22,000,000

4,000,000

60,000,000

41,000,000

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Net increase (decrease) due to changes in estimated future cash flows

749,000,000

Increase in estimated cash flows associated with Zion Station decommissioning

28,000,000

10,000,000

78,000,000

631,000,000

734,000,000

582,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

160,000,000

128,000,000

7,140,000,000

6,507,000,000

Nuclear Decommissioning Asset Retirement Obligation Rollforward [Abstract]

$ 115,000,000

^[1]

3,680,000,000

Net increase (decrease) due to changes in estimated future cash flows

169,000,000

749,000,000

(2,000,000)

Footnotes To Nuclear Decommissioning Asset Retirement Obligation [Abstract]

^[1]

4,596,000,000

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

6,000,000

$ 5,000,000

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[2]

202,000,000

(363,000,000)

352,000,000

(223,000,000)

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[3],[4]

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

$ 22,000,000

$ 4,000,000

$ 60,000,000

$ 41,000,000

[1]	Includes $6 million and $5 million as the current portion of the ARO at September 30, 2012 and December 31, 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.
[2]	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.
[3]	Excludes $22 million of net unrealized gains and $4 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2012 and 2011, respectively, and $60 million and $41 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.
[4]	Net unrealized gains (losses) related to Generation's NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Nuclear Decommissioning (Details) - USD ($)

3 Months Ended

9 Months Ended

Mar. 30, 2012

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Feb. 29, 2012

Dec. 31, 2011

Increase (Decrease) adjustment to nuclear ARO

$ 176,000,000

$ 916,000,000

Increase in estimated cash flows associated with Zion Station decommissioning

28,000,000

10,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

Proposed annual recovery of decommissioning costs

7,140,000,000

$ 6,507,000,000

$ 24,000,000

Current annual recovery of decommissioning costs

29,000,000

78,000,000

631,000,000

734,000,000

582,000,000

160,000,000

128,000,000

Nuclear Decommissioning Asset Retirement Obligation [Abstract]

$ 115,000,000

^[1]

3,680,000,000

Net increase (decrease) due to changes in estimated future cash flows

169,000,000

749,000,000

(2,000,000)

Footnotes To Nuclear Decommissioning Asset Retirement Obligation [Abstract]

^[1]

4,596,000,000

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

6,000,000

5,000,000

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[2]

202,000,000

$ (363,000,000)

352,000,000

$ (223,000,000)

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[3],[4]

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

22,000,000

4,000,000

60,000,000

41,000,000

Nuclear Decommissioning Asset Retirement Obligations [Abstract]

Increase (Decrease) adjustment to nuclear ARO

176,000,000

916,000,000

Increase in estimated cash flows associated with Zion Station decommissioning

28,000,000

10,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

7,140,000,000

6,507,000,000

78,000,000

631,000,000

734,000,000

582,000,000

160,000,000

128,000,000

Nuclear Decommissioning Asset Retirement Obligation [Abstract]

$ 115,000,000

^[1]

3,680,000,000

Net increase (decrease) due to changes in estimated future cash flows

169,000,000

749,000,000

(2,000,000)

Footnotes To Nuclear Decommissioning Asset Retirement Obligation [Abstract]

^[1]

4,596,000,000

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

6,000,000

$ 5,000,000

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[2]

202,000,000

(363,000,000)

352,000,000

(223,000,000)

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[3],[4]

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

$ 22,000,000

$ 4,000,000

$ 60,000,000

$ 41,000,000

Nuclear Decommissioning Trust Fund Investments [Abstract]

Proposed annual recovery of decommissioning costs

24,000,000

Current annual recovery of decommissioning costs

$ 29,000,000

[1]	Includes $6 million and $5 million as the current portion of the ARO at September 30, 2012 and December 31, 2011, respectively, which is included in other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.
[2]	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.
[3]	Excludes $22 million of net unrealized gains and $4 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2012 and 2011, respectively, and $60 million and $41 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.
[4]	Net unrealized gains (losses) related to Generation's NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Retirement Benefits (Details) - USD ($)

2 Months Ended

3 Months Ended

9 Months Ended

Mar. 11, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Pension And Other Postretirement Benefit Contributions [Abstract]

$ 20,000,000

Pension and non-pension postretirement benefit contributions

$ 131,000,000

$ 2,089,000,000

Defined Contribution Plan Contributions By Employer [Abstract]

Future settlement charge to be recorded

$ 16,000,000

$ 26,000,000

49,000,000

64,000,000

Settlement Charges [Abstract]

17,000,000

Exelon Legacy Benefit Plans [Member]

Other comprehensive income (loss) due to an updated valuation adjustment

$ (8,000,000)

Regulatory asset increase (decrease) due to updated valuation adjustment

98,000,000

Constellation Legacy Benefit Plans [Member]

Other comprehensive income (loss) due to an updated valuation adjustment

3,000,000

Other comprehensive income (loss) due to curtailment

(6,000,000)

Regulatory asset increase (decrease) due to updated valuation adjustment

(13,000,000)

Regulatory asset increase (decrease) due to curtailment

44,000,000

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]

20,000,000

11,000,000

63,000,000

36,000,000

Defined Contribution Plan Contributions By Employer [Abstract]

1,000,000

2,000,000

3,000,000

6,000,000

Pension And Other Postretirement Benefit Contributions [Abstract]

9,000,000

Pension and non-pension postretirement benefit contributions

48,000,000

952,000,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

85,000,000

64,000,000

259,000,000

187,000,000

Defined Contribution Plan Contributions By Employer [Abstract]

7,000,000

13,000,000

23,000,000

33,000,000

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

19,000,000

871,000,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

75,000,000

53,000,000

212,000,000

160,000,000

Defined Contribution Plan Contributions By Employer [Abstract]

5,000,000

8,000,000

14,000,000

18,000,000

Regulatory asset increase (decrease) due to contractual termination benefit billed from affiliate

1,000,000

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

12,000,000

110,000,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

12,000,000

8,000,000

38,000,000

24,000,000

Defined Contribution Plan Contributions By Employer [Abstract]

2,000,000

3,000,000

5,000,000

7,000,000

Pension And Other Postretirement Benefit Contributions [Abstract]

3,000,000

Pension and non-pension postretirement benefit contributions

13,000,000

17,000,000

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

$ 12,000,000

14,000,000

^[2]

15,000,000

^[2]

46,000,000

^[2],[3]

43,000,000

^[2],[3]

Defined Contribution Plan Contributions By Employer [Abstract]

$ 1,000,000

1,000,000

^[4]

1,000,000

^[4]

5,000,000

^[4]

5,000,000

^[4]

Regulatory asset increase (decrease) due to contractual termination benefits

3,000,000

Regulatory asset increase (decrease) due to contractual termination benefit billed from affiliate

1,000,000

Total regulatory asset increase (decrease) due to due contractual termination benefit

4,000,000

Pension Plans Defined Benefit [Member]

76,000,000

53,000,000

211,000,000

159,000,000

181,000,000

162,000,000

524,000,000

487,000,000

Components of net periodic benefit cost:

117,000,000

83,000,000

338,000,000

248,000,000

76,000,000

53,000,000

211,000,000

159,000,000

Expected return on assets

181,000,000

162,000,000

524,000,000

487,000,000

(258,000,000)

(235,000,000)

(742,000,000)

(704,000,000)

Prior service cost (credit)

5,000,000

4,000,000

12,000,000

11,000,000

Curtailments/settlements charges

117,000,000

83,000,000

338,000,000

248,000,000

9,000,000

Net periodic benefit cost

^[5]

14,000,000

130,000,000

67,000,000

366,000,000

201,000,000

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

Benefit obligation increase (decrease) reflecting actual census data

86,000,000

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

Benefit obligation increase (decrease) reflecting actual census data

1,000,000

Other comprehensive income (loss) due to curtailment

$ 84,000,000

Discount rate for curtailed plans

3.97%

Other Postretirement Benefit Plans Defined Benefit [Member]

38,000,000

36,000,000

114,000,000

107,000,000

53,000,000

52,000,000

157,000,000

155,000,000

Components of net periodic benefit cost:

19,000,000

16,000,000

58,000,000

49,000,000

38,000,000

36,000,000

114,000,000

107,000,000

Expected return on assets

53,000,000

52,000,000

157,000,000

155,000,000

(28,000,000)

(27,000,000)

(86,000,000)

(83,000,000)

Prior service cost (credit)

Transition obligation

2,000,000

8,000,000

7,000,000

(3,000,000)

(10,000,000)

(29,000,000)

Curtailments/settlements charges

19,000,000

16,000,000

58,000,000

49,000,000

(5,000,000)

(7,000,000)

Net periodic benefit cost

^[5]

6,000,000

76,000,000

$ 69,000,000

240,000,000

$ 206,000,000

Design Changes Impact [Abstract]

Benefit Obligation increase (decrease) due to design changes

212,000,000

Other comprehensive income (loss) due to design changes

(68,000,000)

Regulatory Asset increase (decrease) due to design changes

99,000,000

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

Benefit obligation increase (decrease) reflecting actual census data

$ 25,000,000

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

Benefit obligation increase (decrease) reflecting actual census data

$ (19,000,000)

Benefit obligation increase (decrease) due to curtailment

$ (32,000,000)

Discount rate for curtailed plans

3.98%

Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member]

Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member] | Constellation Legacy Benefit Plans [Member]

Curtailments/settlements

1,000,000

Curtailments/settlements charges

$ 1,000,000

Other Postretirement Benefit Plans Defined Benefit [Member] | Baltimore Gas and Electric Company [Member]

Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Captions [Line Items]

Curtailments/settlements

$ 3,000,000

[1]	These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of September 30, 2012, ComEd and BGE each recorded a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge.
[2]	BGE's pension and other postretirement benefit costs for the nine months ended September 30, 2012 includes a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of September 30, 2012.
[3]	BGE's pension and postretirement benefit costs for the nine months ended September 30, 2012 include $12 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's pension and postretirement benefit costs for the three months and nine months ended September 30, 2011 were $15 million and $43 million, respectively. These amounts are not included in Exelon's net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011 shown in the first table of the Defined Benefit Pension and Other Postretirement Benefits section above.
[4]	BGE's matching contributions for the nine months ended September 30, 2012 include $1 million of costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012, which is not included in Exelon's matching contributions for the nine months ended September 30, 2012.
[5]	As discussed above, ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the second quarter 2012 contractual termination benefit charge.

Retirement Benefits - Assumptions Used In Calculations (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2012
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets			7.50%
Discount rate	3.97%		4.74%
Discount rate from acquisition entity		4.27%
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets			6.68%
Discount rate	3.98%		4.80%
Discount rate from acquisition entity		4.28%
Other Postretirement Benefit Plans Defined Benefit [Member] \| Exelon Legacy Benefit Plans [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract]
Discount rate	3.93%		3.93%
Other Postretirement Benefit Plans Defined Benefit [Member] \| Constellation Legacy Benefit Plans [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract]
Discount rate	3.72%		3.72%

Retirement Benefits - Fair Value Recurring Basis (Details) - USD ($)

Sep. 30, 2012

Dec. 31, 2011

$ 1,117,000,000

$ 861,000,000

^[1]

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

This element represents the portion of the balance sheet assertion valued at fair value by the entity whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission. This item includes currency on hand as well as demand deposits with banks or financial institutions. It also includes other kinds of accounts that have the general characteristics of demand deposits in that the Company may deposit additional funds at any time and also effectively may withdraw funds at any time without prior notice or penalty. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present minimal risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months.

Common Stock without par - Authorized

Retirement Benefits - Additional (Details) - USD ($)	Sep. 30, 2012	Mar. 11, 2012
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	$ 77,000,000
Expected non-qualified pension plan contributions	67,000,000
Expected other postretirement benefit plan contributions	318,000,000
Exelon Generation Co L L C [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	46,000,000
Expected non-qualified pension plan contributions	9,000,000
Expected other postretirement benefit plan contributions	131,000,000
Commonwealth Edison Co [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	9,000,000
Expected non-qualified pension plan contributions	14,000,000
Expected other postretirement benefit plan contributions	116,000,000
PECO Energy Co [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	13,000,000
Expected non-qualified pension plan contributions	1,000,000
Expected other postretirement benefit plan contributions	33,000,000
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Contributions [Abstract]
Expected non-qualified pension plan contributions	1,000,000
Expected other postretirement benefit plan contributions	$ 13,000,000
Expected other postretirement benefit plan contributions for acquired entities		$ 4,000,000

Plant Retirements (Details)	1 Months Ended	9 Months Ended	12 Months Ended
Plant Retirements (Details)	May 31, 2012 USD ($)	Sep. 30, 2012 USD ($) MW	May 31, 2012 USD ($)
Plant Retirements Reserve [Line Items]
Severance benefit obligation - beginning balance		$ 7,000,000
Cash payments		(2,000,000)
Severance benefit obligation - ending balance		$ 5,000,000
Eddystone Generating Station [Member]
Plant Retirements Reliability Must Run Revenue [Abstract]
Monthly revenue during reliability-must-run period	$ 6,000,000
Schuylkill Station Unit One [Member]
Plant Retirement Positions Eliminated [Abstract]
Fossil generating unit capacity to be retired \| MW		166
Riverside Station Unit Six [Member]
Plant Retirement Positions Eliminated [Abstract]
Fossil generating unit capacity to be retired \| MW		115
Exelon Generation Co L L C [Member]
Plant Retirements Reserve [Line Items]
Severance benefit obligation - beginning balance		$ 7,000,000
Cash payments		(2,000,000)
Severance benefit obligation - ending balance		$ 5,000,000
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			$ 6,000,000
Exelon Generation Co L L C [Member] \| Schuylkill Station Unit One [Member]
Plant Retirement Positions Eliminated [Abstract]
Fossil generating unit capacity to be retired \| MW		166
Exelon Generation Co L L C [Member] \| Riverside Station Unit Six [Member]
Plant Retirement Positions Eliminated [Abstract]
Fossil generating unit capacity to be retired \| MW		115

Stock-Based Compensation Plans (Details)

2 Months Ended

3 Months Ended

9 Months Ended

Mar. 11, 2012

USD ($)

$ / shares

Sep. 30, 2012

USD ($)

Years

$ / shares

Sep. 30, 2011

USD ($)

Years

Sep. 30, 2012

USD ($)

Years

$ / shares

Sep. 30, 2011

USD ($)

Years

Dec. 31, 2011

Common Stock [Abstract]

2,000,000,000

Common Stock without par - Outstanding

854,283,102

663,000,000

Authorized Shares for LTIP [Abstract]

Authorized Shares for LTIP

20,000,000

Share Based Compensation Components [Abstract]

Performance shares | $

$ 5,000,000

$ 6,000,000

$ 32,000,000

$ 17,000,000

Stock options | $

2,000,000

1,000,000

13,000,000

7,000,000

Restricted stock units | $

12,000,000

5,000,000

41,000,000

26,000,000

Other stock-based awards | $

1,000,000

3,000,000

Total stock-based compensation included in operating and maintenance expense | $

20,000,000

13,000,000

89,000,000

53,000,000

Income Tax Benefit | $

(8,000,000)

(5,000,000)

(34,000,000)

(21,000,000)

Total after-tax stock based compensation expense | $

12,000,000

8,000,000

55,000,000

32,000,000

Share Based Compensation Pre Tax Expense [Line Items]

Share Based Compensation Acquisition Arrangement [Abstract]

20,000,000

$ 13,000,000

89,000,000

$ 53,000,000

Fair value of stock based compensation used of acquiree | $

$ 71,000,000

Stock based compensation of acquiree converted

12,037,093

No Sale Restricted Stock Converted Shares

165,219

Fair value of each option estimated using the Black-Scholes-Merton option-pricing model

Dividend yield

5.28%

4.84%

5.28%

4.84%

Expected volatility

23.20%

24.40%

23.20%

24.40%

Risk-free interest rate

1.30%

2.65%

1.30%

2.65%

Expected life (years) | Years

6.25

Additional Information Regarding Stock Options Exercised [Abstract]

Unrecognized compensation costs related to nonvested stock options | $

$ 8,000,000

Weighted Average Period Non Vested Stock Options Are Expected To Be Recognized Over | Years

2.5

Restricted Stock Units [Abstract]

$ 58,000,000

1,000,000

Fair value of settled restricted stock | $

4,000,000

$ 1,000,000

23,000,000

$ 19,000,000

Unrecognized compensation costs related to nonvested restricted stock units | $

$ 54,000,000

Weighted average period | Years

2.08

Performance Share Awards [Abstract]

Percentage of current performance share awards settled in stock

50.00%

Percentage of current performance share awards settled in cash

50.00%

Performance shares settled at fair value of | $

$ 22,000,000

21,000,000

Performance shares settled at fair value and paid with cash | $

3,000,000

10,000,000

Unrecognized compensation costs related to nonvested performance shares | $

$ 19,000,000

Weighted average period | Years

2.3

Stock Options [Member]

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Shares outstanding, beginning balance - shares

11,553,761

Converted Options Acquiree

2,372,000

11,194,151

Exercised - shares

1,575,275

Shares outstanding, ending balance - shares

28,142

Expired - shares

488,434

23,028,061

Exercisable stock options - shares

^[1]

20,962,469

Shares outstanding, beginning balance - weighted average exercise price (per share) | $ / shares

$ 48.49

Granted - weighted average exercise price (per share) | $ / shares

$ 39.66

39.66

Converted options of acquiree | $ / shares

41.35

Exercised - weighted average exercise price (per share) | $ / shares

26.57

Forfeited - weighted average exercise price (per share) | $ / shares

44.88

Expired - weighted average exercise price (per share) | $ / shares

48.59

Shares outstanding, ending balance - weighted average exercise price (per share) | $ / shares

45.61

Exercisable stock options - weighted average exercise price (per share) | $ / shares

^[1]

$ 46.08

Share Based Compensation Acquisition Arrangement [Abstract]

Value of stock based compensation converted | $

$ 65,000,000

Nonvested Stock Option [Member]

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Shares outstanding, beginning balance - shares

^[2]

877,050

Converted Options Acquiree

^[3]

2,372,000

8,684,709

11,194,151

Vested - shares

^[3],[4]

11,889,175

Shares outstanding, ending balance - shares

488,434

^[2]

2,065,592

Shares outstanding, beginning balance - weighted average exercise price (per share) | $ / shares

^[2]

$ 48.66

Granted - weighted average exercise price (per share) | $ / shares

^[3]

$ 39.66

39.66

Converted options of acquiree | $ / shares

41.35

Vested - weighted average exercise price (per share) | $ / shares

^[3],[4]

41.39

Forfeited - weighted average exercise price (per share) | $ / shares

48.59

Shares outstanding, ending balance - weighted average exercise price (per share) | $ / shares

^[2]

$ 40.60

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

2,719,671

1,348,000

Stock based compensation issued to retirement eligible employees that vested immediately on the date of the grant.

1,667,000

Restricted Stock [Member]

Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward

Converted options of acquiree | $ / shares

$ 38.91

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

^[5]

1,074,484

Stock Based Compensation Other Than Options Converted Acquiree

1,283,292

825,735

Vested - shares

427,499

Undistributed Vested Awards - shares

47,415

^[6]

602,276

Equity instruments other than options - shares, ending balance

^[5]

2,106,321

Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $ / shares

^[5]

$ 48.08

Granted - Weighted average grant date fair value (per share) | $ / shares

39.93

Vested - Weighted average grant date fair value (per share) | $ / shares

47.69

Forfeited - Weighted average grant date fair value (per share) | $ / shares

$ 42.67

42.67

Undistributed Vested Awards - weighted average exercise price (per share) | $ / shares

^[6]

40.53

Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $ / shares

^[5]

$ 42.27

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

656,228

448,827

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

^[7]

346,848

1,249,932

Vested - shares

159,194

Undistributed Vested Awards - shares

113,761

^[8]

128,370

Equity instruments other than options - shares, ending balance

^[7]

1,195,455

Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $ / shares

^[7]

$ 45.37

Granted - Weighted average grant date fair value (per share) | $ / shares

39.73

Vested - Weighted average grant date fair value (per share) | $ / shares

47.66

Forfeited - Weighted average grant date fair value (per share) | $ / shares

$ 39.79

39.79

Undistributed Vested Awards - weighted average exercise price (per share) | $ / shares

^[8]

40.98

Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $ / shares

^[7]

$ 40.17

Expected Payout Minimum

75.00%

Expected Payout Maximum

125.00%

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

Share Based Compensation Pre Tax Expense [Line Items]

$ 9,000,000

6,000,000

$ 33,000,000

24,000,000

Share Based Compensation Pre Tax Expense [Line Items]

2,000,000

1,000,000

9,000,000

4,000,000

Share Based Compensation Pre Tax Expense [Line Items]

1,000,000

4,000,000

Share Based Compensation Pre Tax Expense [Line Items]

Business Services Company [Member]

$ 2,000,000

1,000,000

^[9]

1,000,000

4,000,000

^[9]

5,000,000

Share Based Compensation Pre Tax Expense [Line Items]

^[10]

$ 7,000,000

$ 5,000,000

$ 39,000,000

^[11]

$ 21,000,000

^[11]

[1]	Includes stock options issued to retirement eligible employees.
[2]	Excludes 2,719,671 and 1,348,000 of stock options issued to retirement-eligible employees as of September 30, 2012 and December 31, 2011, respectively, as they are fully vested.
[3]	Includes 8,684,709 of converted Constellation options that were vested prior to the Merger on March 12, 2012.
[4]	Includes 1,667,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.
[5]	Excludes 656,228 and 448,827 of restricted stock units issued to retirement-eligible employees as of September 30, 2012 and December 31, 2011, respectively, as they are fully vested
[6]	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012.
[7]	Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of September 30, 2012 and December 31, 2011, respectively, as they are fully vested.
[8]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012.
[9]	BGE's stock-based compensation expense for the nine months ended September 30, 2012 includes $2 million of cost incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the nine months ended September 30, 2012 shown in the table titled Components of Stock-Based Compensation Expense above. BGE's stock-based compensation expense for the three and nine months ended September 30, 2011 was $1 million and $5 million, respectively.
[10]	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.
[11]	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.

Earnings Per Share and Equity (Details) - USD ($)	3 Months Ended		9 Months Ended
Earnings Per Share and Equity (Details) - USD ($)	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Earnings Per Share And Equity Additional Narrative Information [Abstract]
Stock options not included in the calculation of diluted common shares outstanding	18,000,000	10,000,000	13,000,000	9,000,000
Treasury Stock, Shares held	35,000,000		35,000,000
Treasury stock, at cost	$ 2,327,000,000		$ 2,327,000,000		$ 2,327,000,000
Earnings Per Share Diluted
Net income on common stock	$ 296,000,000	$ 601,000,000	$ 782,000,000	$ 1,889,000,000
Average common shares outstanding - basic	854,000,000	663,000,000	804,000,000	663,000,000
Assumed exercise of stock options, performance share awards and restricted stock	3,000,000	2,000,000	2,000,000	1,000,000
Average common shares outstanding - diluted	857,000,000	665,000,000	806,000,000	664,000,000

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 13, 14
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-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 128
-Paragraph 40
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Contingent Stock Agreement
-URI http://asc.fasb.org/extlink&oid=6508534

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 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.

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6920599&loc=d3e1448-109256

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Weighted-Average Number of Common Shares Outstanding
-URI http://asc.fasb.org/extlink&oid=6528421

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 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.

Commitments and Contingencies (Details)

1 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

Apr. 12, 2012

Defendants

Feb. 28, 2012

Defendants

Jul. 11, 2011

Customers

Feb. 09, 2007

Jan. 31, 2005

USD ($)

Oct. 31, 2007

USD ($)

Sep. 30, 2012

USD ($)

OpenClaims

MGPSites

Claiments

Tons

Jun. 30, 2011

USD ($)

Sep. 30, 2012

USD ($)

Years

Reactors

OpenClaims

NumberOfGridOperators

NumberOfStates

Customers

MGPSites

Claiments

States

ElectricGenerationStation

Tons

PoundsPerMWh

Dec. 31, 1999

PrincipleResponsibleParties

Jul. 12, 2012

Customers

Dec. 31, 2011

USD ($)

Environmental Issues - Water [Abstract]

$ 14,794,000,000

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

Climate Change Regulation [Abstract]

Minimum GHG emissions by stationary sources to qualify for regulation | Tons

100,000

Minimum additional GHG emissions by stationary sources after a modification | Tons

75,000

Minimum wattage subject to new source performance standards | MW

Effective Number Of Years For Tailoring Rule | Years

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

Cotter Corporation [Member]

Environmental Issues - Solid and Hazardous Waste [Abstract]

Loss Contingency Number Of Defendants | Defendants

Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

$ 434,000,000

217,000,000

135,000,000

94,000,000

32,000,000

137,000,000

Financial Standby Letter of Credit [Member]

1,049,000,000

^[1]

2,290,000,000

Sithe Guarantee [Member]

TEG And TEP Guarantee [Member]

200,000,000

Nuclear Insurance Premiums [Member]

95,000,000

Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

^[2]

2,098,000,000

Commercial Commitments Footnote [Abstract]

^[3]

10,406,000,000

Guarantees in support of equity investment

211,000,000

Estimated net exposure for commercial transaction obligations

1,500,000,000

Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrual For MGP Investigation And Remediation [Member]

351,000,000

$ 224,000,000

Accrual For Environmental Loss Contingencies [Line Items]

307,000,000

168,000,000

Required nuclear liability insurance per site

6,535,000,000

Nuclear Insurance [Abstract]

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

Maximum liability per nuclear incident

$ 2,100,000,000

Environmental Issues - Water [Abstract]

Low end of range of cooling tower cost

430,000,000

Consent decree penalty

$ 1,000,000

Environmental loss contingencies

$ 23,000,000

5,000,000

Environmental loss contingencies payments

$ 18,000,000

Expected economic useful life reduction | Years

Environmental Issues - Air [Abstract]

States subject to the Cross State Air Pollution Rule | States

SO2 emissions allowance impairment

$ 57,000,000

Emissions allowance balance

39,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term direct financing leases

678,000,000

Asbestos Loss Contingency [Abstract]

Asbestos liability reserve

64,000,000

49,000,000

Asbestos liability reserve related to open claims

$ 14,000,000

Open asbestos liability claims | OpenClaims

170

Asbestos liability reserve related to anticipated claims

$ 50,000,000

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

19,000,000

Asbestos reserve adjustment

19,000,000

US Department Of Energy Settlements [Abstract]

Preacquisition contingency asset DOE settlement gain

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

Number of States in PJM | NumberOfStates

Number of grid operators in New York ISO | NumberOfGridOperators

FERC settlement recorded in operation and maintenance expense

$ 195,000,000

FERC settlement recorded as preacquisition contingency

50,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

275,000,000

1,198,000,000

891,000,000

386,000,000

277,000,000

716,000,000

Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract]

$ 3,743,000,000

Percentage of ownership interest in CENG (as a percent)

50.01%

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

Environmental Issues - Solid and Hazardous Waste [Abstract]

DOJ potential settlement

$ 90,000,000

Total cost of remediation to be shared by PRPs

42,000,000

Loss Contingency Number Of Defendants | Defendants

Exelon Generation Co L L C [Member] | Net Capacity Purchases [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[4]

$ 111,000,000

111,000,000

^[4]

375,000,000

^[4]

352,000,000

^[4]

350,000,000

^[4]

266,000,000

^[4]

672,000,000

Exelon Generation Co L L C [Member] | Power Purchases [Member]

^[4]

2,126,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[5]

8,000,000

^[5]

92,000,000

^[5]

62,000,000

^[5]

23,000,000

^[5]

9,000,000

^[5]

8,000,000

Exelon Generation Co L L C [Member] | Transmission Rights Purchases [Member]

^[5]

202,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[6]

8,000,000

^[6]

32,000,000

^[6]

26,000,000

^[6]

13,000,000

^[6]

2,000,000

^[6]

36,000,000

Exelon Generation Co L L C [Member] | Purchased Energy from Equity Investment [Member]

^[6]

117,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

148,000,000

699,000,000

451,000,000

Exelon Generation Co L L C [Member] | Public Utilities, Inventory, Fuel [Member]

1,298,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

263,000,000

1,252,000,000

1,298,000,000

1,279,000,000

929,000,000

3,647,000,000

Exelon Generation Co L L C [Member] | Solar Facility Construction [Member]

8,668,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

192,000,000

Exelon Generation Co L L C [Member] | Wind Facility Construction [Member]

650,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract]

100,000,000

$ 100,000,000

Unrecorded Unconditional Purchase Obligation, Related Megawatts | MW

400

Unrecorded Unconditional Purchase Obligation, Related Megawatts, Under Construction | MW

272

Exelon Generation Co L L C [Member] | Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

248,000,000

$ 248,000,000

110,000,000

91,000,000

69,000,000

8,000,000

29,000,000

Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]

555,000,000

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

^[1]

2,082,000,000

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]

Sale of interest in subsidiary

49.50%

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

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

^[2]

2,098,000,000

Commercial Commitments Footnote [Abstract]

^[7]

2,355,000,000

Guarantees in support of equity investment

211,000,000

Estimated net exposure for commercial transaction obligations

500,000,000

Exelon Generation Co L L C [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

35,000,000

47,000,000

Environmental Issues - MGP Site Contingency [Abstract]

$ 350,000,000

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

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Number Of Stations Violating Clean Air Act | ElectricGenerationStation

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

51,767

Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[8]

$ 0

^[8]

367,000,000

^[8]

323,000,000

^[8]

136,000,000

^[8]

137,000,000

^[8]

140,000,000

Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member]

^[8]

1,103,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[9]

33,000,000

^[9]

71,000,000

^[9]

73,000,000

^[9]

74,000,000

^[9]

76,000,000

^[9]

1,367,000,000

Commonwealth Edison Co [Member] | Other Purchase Obligations [Member]

^[9]

1,694,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

41,000,000

34,000,000

6,000,000

5,000,000

5,000,000

24,000,000

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

115,000,000

Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]

^[1]

142,000,000

Commonwealth Edison Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

200,000,000

Commonwealth Edison Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

^[10]

208,000,000

Accrual For Environmental Loss Contingencies [Line Items]

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

265,000,000

127,000,000

Accrual For Environmental Loss Contingencies [Line Items]

260,000,000

121,000,000

Environmental Issues - MGP Site Contingency [Abstract]

$ 203,000,000

Total number of MGP sites | MGPSites

Approved clean-up | MGPSites

Sites under study/remediation | MGPSites

MGP reserve update

$ 7,000,000

PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[11]

$ 210,000,000

210,000,000

^[11]

413,000,000

^[11]

130,000,000

^[11]

36,000,000

PECO Energy Co [Member] | Alternative Energy Credits [Member]

^[11]

789,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

3,000,000

11,000,000

9,000,000

2,000,000

2,000,000

8,000,000

PECO Energy Co [Member] | Curtailment Services [Member]

35,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

4,000,000

PECO Energy Co [Member] | Public Utilities, Inventory, Fuel [Member]

4,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

55,000,000

114,000,000

68,000,000

53,000,000

31,000,000

91,000,000

PECO Energy Co [Member] | Other Purchase Obligations [Member]

412,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

61,000,000

21,000,000

17,000,000

1,000,000

1,000,000

8,000,000

PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]

109,000,000

PECO Energy Co [Member] | Trust Preferred Securities [Member]

^[1]

22,000,000

PECO Energy Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

178,000,000

PECO Energy Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

^[12]

181,000,000

Accrual For Environmental Loss Contingencies [Line Items]

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

50,000,000

Accrual For Environmental Loss Contingencies [Line Items]

47,000,000

$ 47,000,000

Accrual For Environmental Loss Contingencies [Line Items]

251,000,000

Environmental Issues - MGP Site Contingency [Abstract]

$ 1,000,000

Total number of MGP sites | MGPSites

Sites under study/remediation | MGPSites

68th Street and Sauer Dumps [Abstract]

Maximum estimated clean-up costs for all potentially responsible parties

$ 1,700,000

Asbestos Loss Contingency [Abstract]

Number of claimants | Claiments

480

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

Environmental Issues - Solid and Hazardous Waste [Abstract]

Loss Contingency Number Of Parties Jointly And Severally Liable In Environmental Protection Agency Action | PrincipleResponsibleParties

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]

^[13]

201,000,000

^[13]

707,000,000

^[13]

263,000,000

Baltimore Gas and Electric Company [Member] | Curtailment Services [Member]

^[13]

1,171,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

11,000,000

49,000,000

47,000,000

41,000,000

17,000,000

Baltimore Gas and Electric Company [Member] | Public Utilities, Inventory, Fuel [Member]

165,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

44,000,000

125,000,000

72,000,000

52,000,000

51,000,000

313,000,000

Baltimore Gas and Electric Company [Member] | Other Purchase Obligations [Member]

657,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

17,000,000

2,000,000

Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]

19,000,000

Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]

^[1]

1,000,000

Baltimore Gas and Electric Company [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

250,000,000

^[14]

$ 250,000,000

[1]	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[2]	Does not include potential maximum combined retrospective premium obligations of CENG amounting to $691 million of which Generation's ownership interest is 50.01%.
[3]	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for credit support and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $1.5 billion at September 30, 2012, which represents the total amount Exelon could be required to fund based on September 30, 2012 market prices.
[4]	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at September 30, 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.
[5]	Power-Related Purchases include firm REC purchase agreements. The table excludes renewable energy purchases that are contingent in nature.
[6]	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
[7]	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $211 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.5 billion at September 30, 2012, which represents the total amount Generation could be required to fund based on September 30, 2012 market prices.
[8]	ComEd entered into various contracts for the procurement of electricity that expire between 2012 and 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 4 - Regulatory Matters for additional information.
[9]	ComEd entered into various contracts for the procurement of renewable energy and RECs that expire between 2012 and 2032. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. If events were to occur such that ComEd is not allowed to recover the costs under these contracts from retail customers, ComEd may elect to reduce the annual quantity purchased under these contracts. See Note 4 - Regulatory Matters for additional information.
[10]	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III.
[11]	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2012 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 Program. See Note 4 - Regulatory Matters for additional information.
[12]	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV.
[13]	BGE entered into various contracts for the procurement of electricity that expire between 2012 and 2014. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 - Regulatory Matters for additional information.
[14]	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II.

Supplemental Financial Information - Statement of Operations (Details) - USD ($)

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Taxes Excluding Income And Excise Taxes [Abstract]

$ 6,565,000,000

$ 5,254,000,000

$ 17,205,000,000

$ 14,705,000,000

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

290,000,000

207,000,000

737,000,000

602,000,000

(69,000,000)

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

33,000,000

16,000,000

143,000,000

97,000,000

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

10,000,000

13,000,000

77,000,000

39,000,000

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

202,000,000

(363,000,000)

352,000,000

(223,000,000)

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Net unrealized income (losses) on pledged assets

22,000,000

(4,000,000)

60,000,000

41,000,000

Regulatory offset to decommissioning trust fund-related activities

^[2]

(208,000,000)

281,000,000

(453,000,000)

60,000,000

Total decommissioning-related activities

130,000,000

(198,000,000)

280,000,000

(74,000,000)

Interest income related to uncertain income tax positions

5,000,000

1,000,000

15,000,000

3,000,000

Long-term lease income

7,000,000

22,000,000

21,000,000

7,000,000

14,000,000

53,000,000

Credit facility termination fees

(43,000,000)

(85,000,000)

Bargain purchase gain related to Wolf Hollow acquisition

4,000,000

11,000,000

14,000,000

36,000,000

(2,000,000)

1,000,000

(4,000,000)

1,000,000

101,000,000

(142,000,000)

253,000,000

54,000,000

Taxes Excluding Income And Excise Taxes [Abstract]

4,017,000,000

2,821,000,000

10,509,000,000

7,919,000,000

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

109,000,000

67,000,000

272,000,000

199,000,000

(69,000,000)

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

33,000,000

16,000,000

143,000,000

97,000,000

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

10,000,000

13,000,000

77,000,000

39,000,000

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

202,000,000

(363,000,000)

352,000,000

(223,000,000)

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

71,000,000

(141,000,000)

101,000,000

(88,000,000)

Net unrealized income (losses) on pledged assets

22,000,000

(4,000,000)

60,000,000

41,000,000

Regulatory offset to decommissioning trust fund-related activities

^[2]

(208,000,000)

281,000,000

(453,000,000)

60,000,000

Total decommissioning-related activities

130,000,000

(198,000,000)

280,000,000

(74,000,000)

Interest income related to uncertain income tax positions

1,000,000

2,000,000

1,000,000

33,000,000

Credit facility termination fees

(43,000,000)

(85,000,000)

Bargain purchase gain related to Wolf Hollow acquisition

36,000,000

(6,000,000)

(2,000,000)

(13,000,000)

(7,000,000)

83,000,000

(164,000,000)

185,000,000

(12,000,000)

Taxes Excluding Income And Excise Taxes [Abstract]

1,484,000,000

1,784,000,000

4,154,000,000

4,694,000,000

81,000,000

78,000,000

224,000,000

226,000,000

Interest income related to uncertain income tax positions

1,000,000

1,000,000

12,000,000

1,000,000

13,000,000

1,000,000

2,000,000

6,000,000

3,000,000

2,000,000

8,000,000

5,000,000

5,000,000

16,000,000

12,000,000

24,000,000

Taxes Excluding Income And Excise Taxes [Abstract]

806,000,000

946,000,000

2,396,000,000

2,942,000,000

48,000,000

59,000,000

122,000,000

165,000,000

Interest income related to uncertain income tax positions

1,000,000

2,000,000

3,000,000

1,000,000

1,000,000

2,000,000

3,000,000

8,000,000

1,000,000

(1,000,000)

2,000,000

3,000,000

6,000,000

11,000,000

Taxes Excluding Income And Excise Taxes [Abstract]

720,000,000

745,000,000

2,032,000,000

2,394,000,000

48,000,000

47,000,000

143,000,000

Interest income related to uncertain income tax positions

3,000,000

9,000,000

10,000,000

2,000,000

4,000,000

8,000,000

11,000,000

1,000,000

Depreciation, Amortization and Accretion [Abstract]

$ 5,000,000

$ 8,000,000

$ 18,000,000

$ 22,000,000

[1]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[2]	Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income taxes related to all NDT fund activity for those units. See Note 12 of the Exelon 2011 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

Supplemental Financial Information - Cash Flow (Details) - USD ($)

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

$ 1,263,000,000

$ 947,000,000

Amortization of intangible assets

89,000,000

40,000,000

24,000,000

Amortization of energy contract assets and liabilities

^[1]

731,000,000

Nuclear fuel

^[1]

628,000,000

556,000,000

Asset retirement obligation accretion

^[2]

174,000,000

159,000,000

2,909,000,000

1,702,000,000

Pension and non-pension postretirement benefits costs

606,000,000

407,000,000

Stock-based compensation costs

120,000,000

97,000,000

75,000,000

55,000,000

Other Decommissioning Related Activity

^[3]

(108,000,000)

62,000,000

Energy-related options

^[4]

119,000,000

102,000,000

Amortization of regulatory asset related to debt costs

13,000,000

16,000,000

Amortization of rate stabilization deferral

39,000,000

Amortization of debt fair value adjustment

(49,000,000)

Uncollectible accounts recovery

14,000,000

Discrete impacts from 2010 Rate Case Order

^[5]

(32,000,000)

Bargain purchase gain

$ (36,000,000)

(36,000,000)

Discrete impacts from EIMA

^[6]

43,000,000

Merger related commitments

^[7]

179,000,000

Severance Costs

120,000,000

Gain (loss) on equity method investments

69,000,000

9,000,000

18,000,000

Changes In Other Assets and Liabilities [Abstract]

1,235,000,000

703,000,000

20,000,000

(9,000,000)

463,000,000

52,000,000

(166,000,000)

(40,000,000)

83,000,000

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

(431,000,000)

(92,000,000)

Merger with Constellation, common stock issued

7,365,000,000

Total noncash investing and financing activities

7,365,000,000

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

75,000,000

47,000,000

Smart Grid Grant Reimbursements

85,000,000

86,000,000

Depreciation, Amortization and Accretion [Abstract]

Amortization of intangible assets

540,000,000

416,000,000

24,000,000

Amortization of energy contract assets and liabilities

^[1]

811,000,000

Nuclear fuel

^[1]

629,000,000

556,000,000

Asset retirement obligation accretion

^[2]

174,000,000

159,000,000

2,178,000,000

1,131,000,000

Pension and non-pension postretirement benefits costs

259,000,000

187,000,000

Other Decommissioning Related Activity

14,000,000

^[3]

(108,000,000)

62,000,000

Energy-related options

^[4]

119,000,000

102,000,000

Amortization of debt fair value adjustment

(23,000,000)

Bargain purchase gain

$ (36,000,000)

(36,000,000)

Merger related commitments

^[7]

35,000,000

Severance Costs

34,000,000

Gain (loss) on equity method investments

69,000,000

23,000,000

47,000,000

Changes In Other Assets and Liabilities [Abstract]

422,000,000

362,000,000

(85,000,000)

(46,000,000)

(110,000,000)

(19,000,000)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

(195,000,000)

(65,000,000)

Merger with Constellation, common stock issued

5,258,000,000

Total noncash investing and financing activities

5,258,000,000

Depreciation, Amortization and Accretion [Abstract]

396,000,000

374,000,000

62,000,000

31,000,000

458,000,000

405,000,000

Pension and non-pension postretirement benefits costs

212,000,000

160,000,000

Amortization of regulatory asset related to debt costs

38,000,000

49,000,000

10,000,000

14,000,000

Uncollectible accounts recovery

14,000,000

Discrete impacts from 2010 Rate Case Order

^[5]

(32,000,000)

Discrete impacts from EIMA

^[6]

43,000,000

7,000,000

5,000,000

Changes In Other Assets and Liabilities [Abstract]

310,000,000

210,000,000

21,000,000

(20,000,000)

65,000,000

(12,000,000)

(8,000,000)

(13,000,000)

(72,000,000)

50,000,000

(124,000,000)

29,000,000

Depreciation, Amortization and Accretion [Abstract]

154,000,000

141,000,000

7,000,000

9,000,000

161,000,000

150,000,000

Pension and non-pension postretirement benefits costs

38,000,000

24,000,000

Amortization of regulatory asset related to debt costs

46,000,000

48,000,000

2,000,000

Severance Costs

1,000,000

9,000,000

Changes In Other Assets and Liabilities [Abstract]

96,000,000

74,000,000

(3,000,000)

11,000,000

(7,000,000)

(13,000,000)

(56,000,000)

^[8]

(59,000,000)

(5,000,000)

7,000,000

DOE Smart Grid Investment Grant [Abstract]

(57,000,000)

(28,000,000)

Amount included in capital expenditures

45,000,000

29,000,000

Smart Grid Grant Reimbursements

55,000,000

45,000,000

Depreciation, Amortization and Accretion [Abstract]

184,000,000

170,000,000

34,000,000

35,000,000

218,000,000

205,000,000

Pension and non-pension postretirement benefits costs

44,000,000

43,000,000

Amortization of regulatory asset related to debt costs

28,000,000

31,000,000

1,000,000

Amortization of rate stabilization deferral

49,000,000

45,000,000

Deferral of storm costs

(16,000,000)

Merger related commitments

^[7]

28,000,000

(3,000,000)

(6,000,000)

Changes In Other Assets and Liabilities [Abstract]

147,000,000

98,000,000

21,000,000

(25,000,000)

89,000,000

(13,000,000)

(25,000,000)

(92,000,000)

7,000,000

(50,000,000)

DOE Smart Grid Investment Grant [Abstract]

(86,000,000)

(154,000,000)

Amount included in capital expenditures

30,000,000

18,000,000

Smart Grid Grant Reimbursements

$ 30,000,000

$ 41,000,000

[1]	Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income
[2]	Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income
[3]	Includes the elimination of NDT fund-related 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 12 of the Exelon 2011 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[4]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[5]	In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 4 - Regulatory Matters for more information.
[6]	Includes the establishment of a regulatory asset, pursuant to EIMA, which represents the ICC’s approved distribution formula and associated rulings as of September 30, 2012 and ComEd’s best estimate of the probable increase in distribution rates to provide recovery of prudent and reasonable costs incurred for the twelve months ended December 31, 2011 and the nine months ended September 30, 2012. See Note 4 - Regulatory Matters for more information.
[7]	See Note 3 - Mergers and Acquisitions for more information on merger-related commitments.
[8]	Relates primarily to prepaid utility taxes.

Supplemental Financial Information - Balance Sheet (Details) - USD ($)

12 Months Ended

Dec. 31, 2010

Sep. 30, 2012

Dec. 31, 2011

Supplemental Financial Information Textuals [Abstract]

Payment to IRS

$ 302,000,000

$ 1,502,000,000

$ 1,255,000,000

11,890,000,000

^[1]

10,959,000,000

^[2]

2,161,000,000

1,784,000,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

(310,000,000)

(199,000,000)

Pension and non-pension postretirement benefit plans

459,000,000

488,000,000

(2,887,000,000)

(2,938,000,000)

Net unrealized losses on foreign currency translation

Other comprehensive loss equity investment in CENG

23,000,000

Accumulated unrealized gain (loss) on marketable securities

(2,405,000,000)

(2,450,000,000)

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term leases

678,000,000

1,106,000,000

779,000,000

5,910,000,000

^[1]

5,313,000,000

^[2]

2,161,000,000

1,784,000,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

(85,000,000)

(29,000,000)

Net unrealized losses on foreign currency translation

730,000,000

915,000,000

Other comprehensive loss equity investment in CENG

23,000,000

Accumulated unrealized gain (loss) on marketable securities

(1,000,000)

752,000,000

915,000,000

220,000,000

318,000,000

2,906,000,000

2,750,000,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

(81,000,000)

(78,000,000)

Accumulated unrealized gain (loss) on marketable securities

(1,000,000)

(1,000,000)

Financing Receivable Recorded Investment [Line Items]

87,000,000

83,000,000

Installment plan receivables

21,000,000

Installment plan receivables uncollectible accounts reserve

(18,000,000)

(17,000,000)

2,765,000,000

2,662,000,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

(109,000,000)

(92,000,000)

Accumulated unrealized gain (loss) on marketable securities

1,000,000

PECO Energy Co [Member] | Low To Medium Risk [Member]

1,000,000

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(1,000,000)

PECO Energy Co [Member] | Medium Risk [Member]

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(4,000,000)

(3,000,000)

PECO Energy Co [Member] | High Risk [Member]

Financing Receivable Recorded Investment [Line Items]

Installment plan receivables uncollectible accounts reserve

(13,000,000)

125,000,000

148,000,000

2,579,000,000

2,465,000,000

Accumulated Other Comprehensive Income (Loss) [Abstract]

(35,000,000)

(38,000,000)

Accumulated unrealized gain (loss) on marketable securities

$ 0

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,161 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $1,784 million.

Segment Information (Details)

3 Months Ended

7 Months Ended

9 Months Ended

Sep. 30, 2012

USD ($)

ReportableSegments

Sep. 30, 2011

USD ($)

Sep. 30, 2012

USD ($)

ReportableSegments

Sep. 30, 2012

USD ($)

ReportableSegments

Sep. 30, 2011

USD ($)

Dec. 31, 2011

USD ($)

$ 6,565,000,000

$ 5,254,000,000

$ 17,205,000,000

$ 14,705,000,000

Income taxes

161,000,000

255,000,000

445,000,000

1,034,000,000

Segment Reporting Additional Information [Abstract]

$ 78,353,000,000

$ 54,995,000,000

Number of reportable segments | ReportableSegments

Unrealized Gain (Loss) on Derivatives

$ 377,000,000

(360,000,000)

All Other Segments [Member]

$ 334,000,000

^[1],[2]

203,000,000

^[1],[2]

1,050,000,000

^[3],[4]

576,000,000

^[3],[4]

336,000,000

^[1]

206,000,000

^[1]

1,049,000,000

^[3]

579,000,000

^[3]

(3,000,000)

^[1]

(1,000,000)

^[1]

(101,000,000)

^[3]

(45,000,000)

^[3]

Business Intersegment Eliminations [Member]

^[1]

10,150,000,000

$ 10,150,000,000

10,150,000,000

6,162,000,000

(798,000,000)

^[2]

(503,000,000)

^[2]

(2,291,000,000)

^[4]

(1,429,000,000)

^[4]

(798,000,000)

(503,000,000)

(2,291,000,000)

(1,429,000,000)

Reportable Segment [Member]

(12,523,000,000)

(10,394,000,000)

^[2]

7,000,000

^[2]

4,000,000

^[4]

9,000,000

^[4]

6,565,000,000

^[5]

5,254,000,000

^[5]

17,205,000,000

^[6]

14,705,000,000

^[6]

297,000,000

602,000,000

787,000,000

1,889,000,000

$ 78,353,000,000

54,995,000,000

Segment Reporting Additional Information [Abstract]

Number of reportable segments | ReportableSegments

Exelon Generation Co L L C [Member] | Reportable Segment [Member]

$ 459,000,000

^[2],[7]

304,000,000

^[2],[7]

$ 1,233,000,000

^[4],[8]

856,000,000

^[4],[8]

4,017,000,000

^[5],[7]

2,821,000,000

^[5],[7]

10,509,000,000

^[6],[8]

7,919,000,000

^[6],[8]

87,000,000

^[7]

386,000,000

^[7]

419,000,000

^[8]

1,325,000,000

^[8]

Segment Reporting Additional Information [Abstract]

^[7]

41,090,000,000

$ 41,090,000,000

41,090,000,000

27,433,000,000

Exelon Generation Co L L C [Member] | Reportable Segment [Member] | Baltimore Gas And Electric Company Affiliate [Member]

28,000,000

7,000,000

60,000,000

20,000,000

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

120,000,000

223,000,000

Segment Reporting Additional Information [Abstract]

180,000,000

159,000,000

631,000,000

450,000,000

Unrealized Gain (Loss) on Derivatives

(15,000,000)

30,000,000

Exelon Generation Co L L C [Member] | Reportable Segment [Member] | PECO Energy Co Affiliate [Member]

Generation Mid Atlantic [Member] | Reportable Segment [Member]

171,000,000

137,000,000

407,000,000

394,000,000

1,428,000,000

^[9]

1,032,000,000

^[9]

3,832,000,000

^[10]

3,102,000,000

^[10]

(11,000,000)

(43,000,000)

Revenue net of purchased power and fuel expense from external customers

1,417,000,000

1,032,000,000

3,789,000,000

3,102,000,000

919,000,000

^[11]

835,000,000

2,605,000,000

^[12]

2,567,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(11,000,000)

(44,000,000)

Revenue net of purchased power and fuel expense, Total

908,000,000

835,000,000

2,561,000,000

2,567,000,000

Generation Midwest [Member] | Reportable Segment [Member]

1,193,000,000

^[9]

1,385,000,000

^[9]

3,600,000,000

^[10]

4,151,000,000

^[10]

7,000,000

19,000,000

Revenue net of purchased power and fuel expense from external customers

1,200,000,000

1,385,000,000

3,619,000,000

4,151,000,000

723,000,000

^[11]

852,000,000

2,291,000,000

^[12]

2,704,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

7,000,000

19,000,000

Revenue net of purchased power and fuel expense, Total

730,000,000

852,000,000

2,310,000,000

2,704,000,000

Generation New England [Member] | Reportable Segment [Member]

390,000,000

^[9]

2,000,000

^[9]

776,000,000

^[10]

8,000,000

^[10]

1,000,000

36,000,000

Revenue net of purchased power and fuel expense from external customers

391,000,000

2,000,000

812,000,000

8,000,000

80,000,000

^[11]

1,000,000

144,000,000

^[12]

6,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

1,000,000

36,000,000

Revenue net of purchased power and fuel expense, Total

81,000,000

1,000,000

180,000,000

6,000,000

Generation New York [Member] | Reportable Segment [Member]

183,000,000

^[9]

394,000,000

^[10]

2,000,000

(22,000,000)

Revenue net of purchased power and fuel expense from external customers

185,000,000

372,000,000

11,000,000

^[11]

82,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

2,000,000

(22,000,000)

Revenue net of purchased power and fuel expense, Total

13,000,000

60,000,000

Generation ERCOT [Member] | Reportable Segment [Member]

532,000,000

^[9]

307,000,000

^[9]

1,073,000,000

^[10]

507,000,000

^[10]

1,000,000

Revenue net of purchased power and fuel expense from external customers

533,000,000

307,000,000

1,074,000,000

507,000,000

158,000,000

^[11]

103,000,000

311,000,000

^[12]

94,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

1,000,000

Revenue net of purchased power and fuel expense, Total

158,000,000

103,000,000

312,000,000

94,000,000

Generation Other Regions [Member] | Reportable Segment [Member]

317,000,000

^[9],[13]

77,000,000

^[9],[13]

611,000,000

^[10],[14]

169,000,000

^[10],[14]

12,000,000

^[13]

40,000,000

^[14]

Revenue net of purchased power and fuel expense from external customers

329,000,000

^[13]

77,000,000

^[13]

651,000,000

^[14]

169,000,000

^[14]

30,000,000

^[11],[15]

(4,000,000)

^[15]

49,000,000

^[12],[16]

(10,000,000)

^[12],[16]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

12,000,000

^[15]

41,000,000

^[16]

Revenue net of purchased power and fuel expense, Total

42,000,000

^[15]

(4,000,000)

^[15]

90,000,000

^[16]

(10,000,000)

^[16]

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

4,043,000,000

^[9]

2,803,000,000

^[9]

10,286,000,000

^[10]

7,937,000,000

^[10]

12,000,000

31,000,000

Revenue net of purchased power and fuel expense from external customers

4,055,000,000

2,803,000,000

10,317,000,000

7,937,000,000

1,921,000,000

^[11]

1,787,000,000

5,482,000,000

^[12]

5,361,000,000

^[12]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

11,000,000

31,000,000

Revenue net of purchased power and fuel expense, Total

1,932,000,000

1,787,000,000

5,513,000,000

5,361,000,000

Generation Total Consolidated Group [Member] | All Other Segments [Member]

(35,000,000)

^[9],[17]

18,000,000

^[9],[17]

212,000,000

^[10],[18]

(18,000,000)

^[10],[18]

(3,000,000)

^[17]

(20,000,000)

^[18]

Revenue net of purchased power and fuel expense from external customers

(38,000,000)

^[17]

18,000,000

^[17]

192,000,000

^[18]

(18,000,000)

^[18]

(26,000,000)

^[11],[19]

(37,000,000)

^[19]

9,000,000

^[12],[20]

(237,000,000)

^[12],[20]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(11,000,000)

^[19]

(31,000,000)

^[20]

Revenue net of purchased power and fuel expense, Total

(37,000,000)

^[19]

(37,000,000)

^[19]

(22,000,000)

^[20]

(237,000,000)

^[20]

Generation Total Consolidated Group [Member] | Reportable Segment [Member]

4,008,000,000

^[9]

2,821,000,000

^[9]

10,498,000,000

^[10]

7,919,000,000

^[10]

9,000,000

11,000,000

Revenue net of purchased power and fuel expense from external customers

4,017,000,000

2,821,000,000

10,509,000,000

7,919,000,000

1,895,000,000

^[11]

1,750,000,000

5,491,000,000

^[12]

5,124,000,000

^[12]

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

1,895,000,000

1,750,000,000

5,491,000,000

5,124,000,000

Commonwealth Edison Co [Member] | Reportable Segment [Member]

^[2]

1,000,000

^[2]

2,000,000

^[4]

2,000,000

^[4]

1,484,000,000

^[5]

1,784,000,000

^[5]

4,154,000,000

^[6]

4,694,000,000

^[6]

90,000,000

112,000,000

219,000,000

295,000,000

Segment Reporting Additional Information [Abstract]

22,471,000,000

22,638,000,000

PECO Energy Co [Member] | Reportable Segment [Member]

67,000,000

64,000,000

182,000,000

184,000,000

1,000,000

^[2]

2,000,000

^[2]

3,000,000

^[4]

4,000,000

^[4]

806,000,000

^[5]

946,000,000

^[5]

2,396,000,000

^[6]

2,942,000,000

^[6]

123,000,000

105,000,000

300,000,000

314,000,000

Segment Reporting Additional Information [Abstract]

9,661,000,000

$ 9,156,000,000

Baltimore Gas and Electric Company [Member] | Reportable Segment [Member]

40,000,000

$ 50,000,000

108,000,000

$ 140,000,000

4,000,000

^[2]

7,000,000

^[4],[21]

720,000,000

^[5]

1,388,000,000

^[6],[21]

(50,000,000)

^[21]

Segment Reporting Additional Information [Abstract]

7,504,000,000

$ 7,504,000,000

7,504,000,000

$ 20,000,000

$ 42,000,000

[1]	Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities.
[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 2 of the Exelon 2011 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.
[3]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[4]	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 2 of the Exelon 2011 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.
[5]	For the three months ended September 30, 2012 and 2011, utility taxes of $28 million and $7 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2012 and 2011, utility taxes of $67 million and $64 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2012 and 2011, utility taxes of $40 million and $50 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2012, utility taxes of $20 million are included in revenues and expenses for BGE.
[6]	For the nine months ended September 30, 2012 and 2011, utility taxes of $ 60 million and $ 20 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2012 and 2011, utility taxes of $182 million and $184 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2012 and 2011, utility taxes of $108 million and $140 million, respectively, are included in revenues and expenses for PECO. For the period of March 12, 2012 through September 30, 2012, utility taxes of $42 million are included in revenues and expenses for BGE.
[7]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended September 30, 2012 include revenue from sales to PECO of $ 171 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $180 million in the Midwest region, net of $ (15) million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the three months ended September 30, 2011 intersegment revenues for Generation include revenue from sales to PECO of $137 million in the Mid-Atlantic region, and sales to ComEd of $159 million in the Midwest region.
[8]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2012 include revenue from sales to PECO of $407 million and sales to BGE of $223 million in the Mid-Atlantic region, and sales to ComEd of $631 million in the Midwest region, net of $ (30) million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the nine months ended September 30, 2011 intersegment revenues for Generation include revenue from sales to PECO of $394 million in the Mid-Atlantic region, and sales to ComEd of $450 million in the Midwest region.
[9]	Includes all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE.
[10]	Includes all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE.
[11]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
[12]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
[13]	Other regions includes the South, West and Canada, which are not considered individually significant.
[14]	Other regions include the South, West and Canada, which are not considered individually significant.
[15]	Other regions includes the South, West and Canada, which are not considered individually significant.
[16]	Other regions includes the South, West and Canada, which are not considered individually significant.
[17]	Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation's economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.
[18]	Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation's economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.
[19]	Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation's economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.
[20]	Other represents activities not allocated to a region and includes retail and wholesale gas, upstream natural gas, proprietary trading, demand response, energy efficiency, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, mark-to-market activities associated with Generation's economic hedging activities. In addition, includes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.
[21]	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through September 30, 2012.

Related Party Transactions (Details) - USD ($)

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2012

Sep. 30, 2011

Dec. 31, 2011

$ 6,000,000

$ 19,000,000

(69,000,000)

1,226,000,000

1,044,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

$ 0

Mark-to-market derivative liabilities with affiliate (current liabilities)

371,000,000

15,000,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

459,000,000

304,000,000

1,233,000,000

856,000,000

126,000,000

77,000,000

437,000,000

222,000,000

Cash distribution paid to member

(69,000,000)

1,384,000,000

61,000,000

Contributions from member

30,000,000

Total receivables from affiliates (current)

352,000,000

^[1]

352,000,000

^[1]

503,000,000

^[2]

130,000,000

109,000,000

Mark-to-market derivative assets with affiliate (noncurrent assets)

191,000,000

^[2]

348,000,000

1,000,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

99,000,000

58,000,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

Total payables to affiliates (noncurrent)

2,383,000,000

2,222,000,000

Purchased power from affiliate

1,000,000

2,000,000

180,000,000

159,000,000

631,000,000

450,000,000

37,000,000

40,000,000

118,000,000

113,000,000

3,000,000

4,000,000

9,000,000

11,000,000

Contributions from parent

95,000,000

225,000,000

Total receivable from affiliates (noncurrent)

2,024,000,000

1,860,000,000

6,000,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

84,000,000

111,000,000

352,000,000

503,000,000

Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)

191,000,000

Purchased power from affiliate

1,000,000

2,000,000

3,000,000

4,000,000

171,000,000

137,000,000

407,000,000

394,000,000

27,000,000

24,000,000

83,000,000

68,000,000

3,000,000

9,000,000

Contributions from parent

258,000,000

268,000,000

18,000,000

Total receivable from affiliates (noncurrent)

362,000,000

365,000,000

8,000,000

Mark-to-market derivative liabilities with affiliate (current liabilities)

76,000,000

62,000,000

4,000,000

3,000,000

9,000,000

6,000,000

29,000,000

26,000,000

97,000,000

96,000,000

$ 0

Contributions from parent

$ 85,000,000

66,000,000

8,000,000

Under Recovered Energy And Transmission Costs [Member]

$ 44,000,000

$ 41,000,000

[1]	Current and noncurrent assets are shown net of collateral of $92 million and $263 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(49) million and $(113) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $193 million at September 30, 2012.
[2]	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.

Quarterly Data (Details) - USD ($)	3 Months Ended		9 Months Ended
Quarterly Data (Details) - USD ($)	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Earnings Per Share Basic [Abstract]
Average common shares outstanding - basic	854,000,000	663,000,000	804,000,000	663,000,000
Earnings Per Share, Basic	$ 0.35	$ 0.91	$ 0.97	$ 2.85
Earnings Per Share Diluted
Average common shares outstanding - diluted	857,000,000	665,000,000	806,000,000	664,000,000
Earnings Per Share, Diluted	$ 0.35	$ 0.90	$ 0.97	$ 2.84
Selected Quarterly Financial Information [Line Items]
Revenues	$ 6,565,000,000	$ 5,254,000,000	$ 17,205,000,000	$ 14,705,000,000
Operating Income (Loss)	603,000,000	1,181,000,000	1,676,000,000	3,417,000,000
Net Income Loss	297,000,000	602,000,000	787,000,000	1,892,000,000
Exelon Generation Co L L C [Member]
Selected Quarterly Financial Information [Line Items]
Revenues	4,017,000,000	2,821,000,000	10,509,000,000	7,919,000,000
Operating Income (Loss)	174,000,000	754,000,000	830,000,000	2,203,000,000
Net Income Loss	87,000,000	386,000,000	419,000,000	1,325,000,000
Commonwealth Edison Co [Member]
Selected Quarterly Financial Information [Line Items]
Revenues	1,484,000,000	1,784,000,000	4,154,000,000	4,694,000,000
Operating Income (Loss)	218,000,000	243,000,000	586,000,000	697,000,000
Net Income Loss	90,000,000	112,000,000	219,000,000	295,000,000
PECO Energy Co [Member]
Selected Quarterly Financial Information [Line Items]
Revenues	806,000,000	946,000,000	2,396,000,000	2,942,000,000
Operating Income (Loss)	178,000,000	153,000,000	506,000,000	524,000,000
Net Income Loss	123,000,000	105,000,000	300,000,000	314,000,000
Baltimore Gas and Electric Company [Member]
Selected Quarterly Financial Information [Line Items]
Revenues	720,000,000	745,000,000	2,032,000,000	2,394,000,000
Operating Income (Loss)	30,000,000	23,000,000	71,000,000	229,000,000
Net Income Loss	$ 0	$ 2,000,000	$ (14,000,000)	$ 99,000,000

Subsequent Event (Details)	9 Months Ended
Subsequent Event (Details)	Sep. 30, 2012 USD ($) Customers
PECO Energy Co [Member]
Storm Damage Impact [Abstract]
Customers impacted from storm damage \| Customers	850,000
Incremental operating and maintenance expense from storm damage (low estimate)	$ 49,000,000
Incremental operating and maintenance expense from storm damage (high estimate)	55,000,000
Incremental capital expenditures from storm damage (low estimate)	32,000,000
Incremental capital expenditures from storm damage (high estimate)	$ 36,000,000
Baltimore Gas and Electric Company [Member]
Storm Damage Impact [Abstract]
Customers impacted from storm damage \| Customers	325,000
Incremental operating and maintenance expense from storm damage (low estimate)	$ 33,000,000
Incremental operating and maintenance expense from storm damage (high estimate)	37,000,000
Incremental capital expenditures from storm damage (low estimate)	13,000,000
Incremental capital expenditures from storm damage (high estimate)	$ 14,000,000

Label

Element

Value

us-gaap_RegulatoryAssetsCurrent

$ 62,000,000

us-gaap_RegulatoryAssetsCurrent

57,000,000

us-gaap_RegulatoryAssetsNoncurrent

Under Recovered Distribution Service Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

14,000,000

us-gaap_RegulatoryAssetsNoncurrent

119,000,000

Electric Generation Related Regulatory Asset [Member]

us-gaap_RegulatoryAssetsNoncurrent

70,000,000

us-gaap_RegulatoryAssetsCurrent

16,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

44,000,000

Fair Value Of Supply Contract [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

94,000,000

^[1]

Energy Efficiency And Demand Response Programs [Member]

us-gaap_RegulatoryAssetsNoncurrent

31,000,000

^[1]

us-gaap_RegulatoryAssetsCurrent

55,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

117,000,000

us-gaap_RegulatoryAssetsNoncurrent

AMI Expenses [Member]

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsNoncurrent

54,000,000

Other Regulatory Assets [Member]

us-gaap_RegulatoryAssetsNoncurrent

28,000,000

us-gaap_RegulatoryAssetsCurrent

30,000,000

us-gaap_RegulatoryAssetsCurrent

17,000,000

us-gaap_RegulatoryAssetsNoncurrent

27,000,000

RTO Startup Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

Under Recovered Universal Service Fund Costs Member [Member]

us-gaap_RegulatoryAssetsNoncurrent

4,000,000

us-gaap_RegulatoryAssetsCurrent

8,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

Rate Stabilization Deferral [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

65,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

244,000,000

Fair Value Of Long Term Debt [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

43,000,000

^[2]

Deferred Storm Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

226,000,000

^[2]

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

7,000,000

DSP Program costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

3,000,000

DSP II Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

Financial Swap with Generation [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

DSP Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

2,000,000

Pension and Other Postretirement Benefits [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

264,000,000

^[3]

us-gaap_RegulatoryAssetsCurrent

204,000,000

us-gaap_RegulatoryAssetsNoncurrent

3,499,000,000

^[3]

Renewable Energy And Associated REC [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,794,000,000

us-gaap_RegulatoryAssetsCurrent

17,000,000

us-gaap_RegulatoryAssetsCurrent

9,000,000

us-gaap_RegulatoryAssetsNoncurrent

53,000,000

Deferred Income Taxes [Member]

us-gaap_RegulatoryAssetsNoncurrent

97,000,000

us-gaap_RegulatoryAssetsCurrent

13,000,000

us-gaap_RegulatoryAssetsCurrent

5,000,000

us-gaap_RegulatoryAssetsNoncurrent

1,346,000,000

MGP Remediation Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

1,176,000,000

us-gaap_RegulatoryAssetsCurrent

65,000,000

us-gaap_RegulatoryAssetsCurrent

30,000,000

us-gaap_RegulatoryAssetsNoncurrent

227,000,000

Asset Retirement Obligations [Member]

us-gaap_RegulatoryAssetsNoncurrent

129,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

84,000,000

us-gaap_RegulatoryAssetsNoncurrent

74,000,000

Debt Costs [Member]

us-gaap_RegulatoryAssetsCurrent

14,000,000

us-gaap_RegulatoryAssetsCurrent

18,000,000

us-gaap_RegulatoryAssetsNoncurrent

71,000,000

us-gaap_RegulatoryAssetsNoncurrent

81,000,000

Severance [Member]

us-gaap_RegulatoryAssetsCurrent

30,000,000

us-gaap_RegulatoryAssetsCurrent

25,000,000

us-gaap_RegulatoryAssetsNoncurrent

36,000,000

Operating Revenue [Member]

us-gaap_RegulatoryAssetsNoncurrent

38,000,000

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

Operating Revenue [Member] | Pro Forma [Member]

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(74,000,000)

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(330,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

44,000,000

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

31,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(374,000,000)

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(105,000,000)

Purchased Power And Fuel [Member]

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(359,000,000)

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(79,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

13,000,000

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

22,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(372,000,000)

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

(101,000,000)

Purchased Power And Fuel [Member] | Pro Forma [Member]

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(29,000,000)

Other Derivatives Not Designated As Hedging Instruments Gain Loss Net

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsGainLossNet

(5,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

(9,000,000)

Other Derivatives Not Designated As Hedging Instruments Change In Fair Value

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsChangeInFairValue

(31,000,000)

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

4,000,000

Other Derivatives Not Designated As Hedging Instruments Reclassification To Realized At Settlement

exc_OtherDerivativesNotDesignatedAsHedgingInstrumentsReclassificationToRealizedAtSettlement

2,000,000

Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member]

us-gaap_RegulatoryAssetsCurrent

33,000,000

us-gaap_RegulatoryAssetsCurrent

50,000,000

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

16,000,000

us-gaap_RegulatoryAssetsCurrent

16,000,000

us-gaap_RegulatoryAssetsNoncurrent

44,000,000

Baltimore Gas and Electric Company [Member] | Fair Value Of Supply Contract [Member]

us-gaap_RegulatoryAssetsNoncurrent

56,000,000

us-gaap_RegulatoryAssetsCurrent

^[1]

Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[1]

us-gaap_RegulatoryAssetsCurrent

55,000,000

us-gaap_RegulatoryAssetsCurrent

29,000,000

us-gaap_RegulatoryAssetsNoncurrent

117,000,000

Baltimore Gas and Electric Company [Member] | AMI Expenses [Member]

us-gaap_RegulatoryAssetsNoncurrent

95,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

Baltimore Gas and Electric Company [Member] | Other Regulatory Assets [Member]

us-gaap_RegulatoryAssetsNoncurrent

15,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

5,000,000

Baltimore Gas and Electric Company [Member] | RTO Startup Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Under Recovered Universal Service Fund Costs Member [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Rate Stabilization Deferral [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

65,000,000

us-gaap_RegulatoryAssetsCurrent

63,000,000

us-gaap_RegulatoryAssetsNoncurrent

244,000,000

Baltimore Gas and Electric Company [Member] | Fair Value Of Long Term Debt [Member]

us-gaap_RegulatoryAssetsNoncurrent

295,000,000

us-gaap_RegulatoryAssetsCurrent

^[2]

Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[2]

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

7,000,000

Baltimore Gas and Electric Company [Member] | DSP II Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

us-gaap_RegulatoryAssetsCurrent

Baltimore Gas and Electric Company [Member] | Financial Swap with Generation [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | DSP Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Pension and Other Postretirement Benefits [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

1,000,000

^[3]

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

^[3]

Baltimore Gas and Electric Company [Member] | Renewable Energy And Associated REC [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Deferred Income Taxes [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

8,000,000

us-gaap_RegulatoryAssetsCurrent

7,000,000

us-gaap_RegulatoryAssetsNoncurrent

64,000,000

Baltimore Gas and Electric Company [Member] | MGP Remediation Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

64,000,000

us-gaap_RegulatoryAssetsCurrent

1,000,000

us-gaap_RegulatoryAssetsCurrent

1,000,000

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Baltimore Gas and Electric Company [Member] | Debt Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

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

us-gaap_RegulatoryAssetsNoncurrent

10,000,000

us-gaap_RegulatoryAssetsCurrent

5,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

17,000,000

PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

1,000,000

us-gaap_RegulatoryAssetsCurrent

7,000,000

^[4]

us-gaap_RegulatoryAssetsCurrent

9,000,000

^[4]

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Fair Value Of Supply Contract [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

^[1]

PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[1]

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | AMI Expenses [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

24,000,000

PECO Energy Co [Member] | Other Regulatory Assets [Member]

us-gaap_RegulatoryAssetsNoncurrent

22,000,000

us-gaap_RegulatoryAssetsCurrent

14,000,000

us-gaap_RegulatoryAssetsCurrent

8,000,000

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

PECO Energy Co [Member] | RTO Startup Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

12,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Under Recovered Universal Service Fund Costs Member [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

8,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Rate Stabilization Deferral [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Fair Value Of Long Term Debt [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

^[2]

PECO Energy Co [Member] | Deferred Storm Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[2]

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | DSP II Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

PECO Energy Co [Member] | Financial Swap with Generation [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

PECO Energy Co [Member] | Pension and Other Postretirement Benefits [Member]

us-gaap_RegulatoryAssetsNoncurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

^[3]

us-gaap_RegulatoryAssetsCurrent

7,000,000

us-gaap_RegulatoryAssetsNoncurrent

^[3]

PECO Energy Co [Member] | Renewable Energy And Associated REC [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

PECO Energy Co [Member] | Deferred Income Taxes [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

1,220,000,000

PECO Energy Co [Member] | MGP Remediation Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

1,110,000,000

us-gaap_RegulatoryAssetsCurrent

6,000,000

us-gaap_RegulatoryAssetsCurrent

6,000,000

us-gaap_RegulatoryAssetsNoncurrent

35,000,000

PECO Energy Co [Member] | Asset Retirement Obligations [Member]

us-gaap_RegulatoryAssetsNoncurrent

38,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

25,000,000

PECO Energy Co [Member] | Debt Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

24,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

PECO Energy Co [Member] | Severance [Member]

us-gaap_RegulatoryAssetsNoncurrent

8,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

22,000,000

us-gaap_RegulatoryAssetsCurrent

48,000,000

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

Net Regulatory Asset

exc_NetRegulatoryAsset

84,000,000

Net Regulatory Asset

exc_NetRegulatoryAsset

74,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

14,000,000

us-gaap_RegulatoryAssetsNoncurrent

119,000,000

Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member]

us-gaap_RegulatoryAssetsNoncurrent

70,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Fair Value Of Supply Contract [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

^[1]

Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[1]

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | AMI Expenses [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsNoncurrent

5,000,000

Commonwealth Edison Co [Member] | Other Regulatory Assets [Member]

us-gaap_RegulatoryAssetsNoncurrent

6,000,000

us-gaap_RegulatoryAssetsCurrent

16,000,000

us-gaap_RegulatoryAssetsCurrent

9,000,000

us-gaap_RegulatoryAssetsNoncurrent

14,000,000

Commonwealth Edison Co [Member] | RTO Startup Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

13,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

Commonwealth Edison Co [Member] | Under Recovered Universal Service Fund Costs Member [Member]

us-gaap_RegulatoryAssetsNoncurrent

4,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Rate Stabilization Deferral [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Fair Value Of Long Term Debt [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

^[2]

Commonwealth Edison Co [Member] | Deferred Storm Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[2]

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | DSP II Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

Commonwealth Edison Co [Member] | Financial Swap with Generation [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

352,000,000

us-gaap_RegulatoryAssetsCurrent

503,000,000

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member]

us-gaap_RegulatoryAssetsNoncurrent

191,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

Commonwealth Edison Co [Member] | Pension and Other Postretirement Benefits [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

^[3]

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

^[3]

Commonwealth Edison Co [Member] | Renewable Energy And Associated REC [Member]

us-gaap_RegulatoryAssetsNoncurrent

us-gaap_RegulatoryAssetsCurrent

17,000,000

us-gaap_RegulatoryAssetsCurrent

9,000,000

us-gaap_RegulatoryAssetsNoncurrent

53,000,000

Commonwealth Edison Co [Member] | Deferred Income Taxes [Member]

us-gaap_RegulatoryAssetsNoncurrent

97,000,000

us-gaap_RegulatoryAssetsCurrent

5,000,000

us-gaap_RegulatoryAssetsCurrent

5,000,000

us-gaap_RegulatoryAssetsNoncurrent

62,000,000

Commonwealth Edison Co [Member] | MGP Remediation Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

66,000,000

us-gaap_RegulatoryAssetsCurrent

58,000,000

us-gaap_RegulatoryAssetsCurrent

24,000,000

us-gaap_RegulatoryAssetsNoncurrent

190,000,000

Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member]

us-gaap_RegulatoryAssetsNoncurrent

91,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

59,000,000

Commonwealth Edison Co [Member] | Debt Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

50,000,000

us-gaap_RegulatoryAssetsCurrent

11,000,000

us-gaap_RegulatoryAssetsCurrent

15,000,000

us-gaap_RegulatoryAssetsNoncurrent

65,000,000

Commonwealth Edison Co [Member] | Severance [Member]

us-gaap_RegulatoryAssetsNoncurrent

73,000,000

us-gaap_RegulatoryAssetsCurrent

25,000,000

us-gaap_RegulatoryAssetsCurrent

25,000,000

us-gaap_RegulatoryAssetsNoncurrent

19,000,000