SEC Filing | Exelon Corporation

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e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Quarterly Period Ended June 30, 2007
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


	Name of Registrant; State of Incorporation;	IRS Employer
Commission	Address of Principal Executive Offices; and	Identification
File Number	Telephone Number	Number

1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.

The number of shares outstanding of each registrant’s common stock as of June 30, 2007 was:


Exelon Corporation Common Stock, without par value		674,171,814
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,519
PECO Energy Company Common Stock, without par value		170,478,507

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

Accelerated Filer

Non-accelerated Filer

Exelon Corporation

Exelon Generation Company, LLC

Commonwealth Edison Company

PECO Energy Company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company Yes o No þ.

TABLE OF CONTENTS


		Page No.

FILING FORMAT			3
FORWARD-LOOKING STATEMENTS			3
WHERE TO FIND MORE INFORMATION			3

PART I.	FINANCIAL INFORMATION		4
ITEM 1.	FINANCIAL STATEMENTS		4
	Exelon Corporation		5
	Consolidated Statements of Operations and Comprehensive Income		5
	Consolidated Statements of Cash Flows		6
	Consolidated Balance Sheets		7
	Consolidated Statement of Changes in Shareholders’ Equity		9
	Exelon Generation Company, LLC		10
	Consolidated Statements of Operations and Comprehensive Income		10
	Consolidated Statements of Cash Flows		11
	Consolidated Balance Sheets		12
	Consolidated Statement of Changes in Member’s Equity		14
	Commonwealth Edison Company		15
	Consolidated Statements of Operations and Comprehensive Income		15
	Consolidated Statements of Cash Flows		16
	Consolidated Balance Sheets		17
	Consolidated Statement of Changes in Shareholders’ Equity		19
	PECO Energy Company		20
	Consolidated Statements of Operations and Comprehensive Income		20
	Consolidated Statements of Cash Flows		21
	Consolidated Balance Sheets		22
	Consolidated Statement of Changes in Shareholders’ Equity		24
	Combined Notes to Consolidated Financial Statements
	1. Basis of Presentation		25
	2. Discontinued Operations		26
	3. New Accounting Pronouncements		26
	4. Acquisitions and Dispositions		28
	5. Regulatory Issues		28
	6. Intangible Assets		40
	7. Debt and Credit Agreements		40
	8. Derivative Financial Instruments		43
	9. Retirement Benefits		49
	10. Income Taxes		52
	11. Asset Retirement Obligations		59
	12. Earnings Per Share and Shareholders’ Equity		60
	13. Commitments and Contingencies		62
	14. Supplemental Financial Information		73
	15. Segment Information		80
	16. Related-Party Transactions		83
	17. Subsequent Events		91


		Page No.

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		92
	Exelon Corporation		92
	Exelon Generation Company, LLC		149
	Commonwealth Edison Company		151
	PECO Energy Company		153
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		155
ITEM 4.	CONTROLS AND PROCEDURES		162
ITEM 4T.	CONTROLS AND PROCEDURES		163

PART II.	OTHER INFORMATION		164
ITEM 1.	LEGAL PROCEEDINGS		164
ITEM 1A.	RISK FACTORS		164
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		165
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		165
ITEM 5.	OTHER INFORMATION		166
ITEM 6.	EXHIBITS		167

SIGNATURES			168
	Exelon Corporation		168
	Exelon Generation Company, LLC		168
	Commonwealth Edison Company		169
	PECO Energy Company		169

CERTIFICATION EXHIBITS			170
	Exelon Corporation		170, 178
	Exelon Generation Company, LLC		172, 180
	Commonwealth Edison Company		174, 182
	PECO Energy Company		176, 184

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation (Exelon), Exelon Generation Company, LLC (Generation), Commonwealth Edison Company (ComEd), and PECO Energy Company (PECO) (collectively, the Registrants). Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include (a) those factors discussed in the following sections of the Registrants’ 2006 Annual Report on Form 10-K: ITEM 1A. Risk Factors, as updated by Part II, Item 1A of this Report, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8. Financial Statements and Supplementary Data: Note 18, as updated by Note 13 of this Report; and (b) other factors discussed herein and in other filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC at www.sec.gov and the Registrant’s websites at www.exeloncorp.com. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions, except per share data)	2007			2006			2007			2006

Operating revenues	$	4,501		$	3,697		$	9,330		$	7,559
Operating expenses
Purchased power		1,118			571			2,363			1,096
Fuel		522			502			1,292			1,438
Operating and maintenance		1,062			881			2,120			1,906
Depreciation and amortization		369			371			738			735
Taxes other than income		199			170			395			364

Total operating expenses		3,270			2,495			6,908			5,539

Operating income		1,231			1,202			2,422			2,020

Other income and deductions
Interest expense		(161	)		(154	)		(318	)		(306	)
Interest expense to affiliates, net		(53	)		(68	)		(109	)		(139	)
Equity in losses of unconsolidated affiliates and investments		(43	)		(22	)		(69	)		(61	)
Other, net		43			46			106			91

Total other income and deductions		(214	)		(198	)		(390	)		(415	)

Income from continuing operations before income taxes		1,017			1,004			2,032			1,605
Income taxes		314			363			648			564

Income from continuing operations		703			641			1,384			1,041

Discontinued operations
Income (loss) from discontinued operations (net of taxes of $0 and $2 for the three and six months ended June 30, 2007, respectively)		(1	)		—			4			—
Gain on disposal of discontinued operations (net of taxes of $0, $3, $2 and $(1) for the three and six months ended June 30, 2007 and 2006, respectively)		—			3			5			3

Income (loss) from discontinued operations, net		(1	)		3			9			3

Net income		702			644			1,393			1,044

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost ($2, $(4), $4 and $(10) related to pension and non-pension postretirement benefit plans for the three and six months ended June 30, 2007, respectively)		(2	)		—			(6	)		—
Actuarial loss reclassified to periodic benefit cost ($12, $1, $31 and $8 related to pension and non-pension postretirement benefit plans for the three and six months ended June 30, 2007, respectively)		13			—			39			—
Transition obligation reclassified to periodic benefit cost ($0, $0, $0 and $2 related to pension and non-pension postretirement benefit plans for the three and six months ended June 30, 2007, respectively)		—			—			2			—
Finalization of pension and non-pension postretirement benefit plans valuation		19			—			19			—
Change in unrealized gain (loss) on cash-flow hedges		210			140			(209	)		232
Unrealized gain (loss) on marketable securities		29			(13	)		38			15

Other comprehensive income (loss)		269			127			(117	)		247

Comprehensive income	$	971		$	771		$	1,276		$	1,291

Average shares of common stock outstanding:
Basic		675			670			674			669
Diluted		680			676			679			675

Earnings per average common share — basic:
Income from continuing operations	$	1.04		$	0.96		$	2.05		$	1.56
Income from discontinued operations		—			—			0.02			—

Net income	$	1.04		$	0.96		$	2.07		$	1.56

Earnings per average common share — diluted:
Income from continuing operations	$	1.03		$	0.95		$	2.04		$	1.55
Income from discontinued operations		—			—			0.01			—

Net income	$	1.03		$	0.95		$	2.05		$	1.55

Dividends per common share	$	0.44		$	0.40		$	0.88		$	0.80

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2007			2006

Cash flows from operating activities
Net income	$	1,393		$	1,044
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		1,066			1,060
Deferred income taxes and amortization of investment tax credits		(128	)		(81	)
Net realized and unrealized mark-to-market transactions		120			(69	)
Impairment of long-lived assets		—			117
Other non-cash operating activities		369			124
Changes in assets and liabilities:
Accounts receivable		(304	)		230
Inventories		69			11
Accounts payable, accrued expenses and other current liabilities		(122	)		(406	)
Counterparty collateral asset		(231	)		178
Counterparty collateral liability		(264	)		5
Income taxes		87			300
Restricted cash		(42	)		—
Pension and non-pension postretirement benefit contributions		(40	)		(30	)
Other assets and liabilities		(347	)		(295	)

Net cash flows provided by operating activities		1,626			2,188

Cash flows from investing activities
Capital expenditures		(1,284	)		(1,156	)
Proceeds from nuclear decommissioning trust fund sales		2,268			2,554
Investment in nuclear decommissioning trust funds		(2,402	)		(2,706	)
Proceeds from sale of investments		95			1
Change in restricted cash		2			1
Other investing activities		(46	)		(54	)

Net cash flows used in investing activities		(1,367	)		(1,360	)

Cash flows from financing activities
Issuance of long-term debt		465			326
Retirement of long-term debt		(198	)		(34	)
Retirement of long-term debt to financing affiliates		(534	)		(422	)
Change in short-term debt		348			(106	)
Dividends paid on common stock		(592	)		(535	)
Proceeds from employee stock plans		145			107
Purchase of treasury stock		(37	)		(53	)
Other financing activities		55			31

Net cash flows used in financing activities		(348	)		(686	)

(Decrease) Increase in cash and cash equivalents		(89	)		142
Cash and cash equivalents at beginning of period		224			140

Cash and cash equivalents at end of period	$	135		$	282

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
(In millions)	2007		2006

ASSETS
Current assets
Cash and cash equivalents	$	135	$	224
Restricted cash and investments		98		58
Accounts receivable, net
Customer		2,046		1,747
Other		423		462
Mark-to-market derivative assets		765		1,418
Inventories, net
Fossil fuel		238		300
Materials and supplies		431		431
Other		823		352

Total current assets		4,959		4,992

Property, plant and equipment, net		23,431		22,775
Deferred debits and other assets
Regulatory assets		5,438		5,808
Nuclear decommissioning trust funds		6,777		6,415
Investments		664		725
Investments in affiliates		73		85
Goodwill		2,641		2,694
Mark-to-market derivative assets		210		171
Other		1,112		654

Total deferred debits and other assets		16,915		16,552

Total assets	$	45,305	$	44,319

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,			December 31,
(In millions)	2007			2006

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	653		$	305
Long-term debt due within one year		935			248
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year		510			581
Accounts payable		1,289			1,382
Mark-to-market derivative liabilities		649			1,015
Accrued expenses		814			1,180
Other		511			1,084

Total current liabilities		5,361			5,795

Long-term debt		8,477			8,896
Long-term debt to ComEd Transitional Funding Trust and PECO
Energy Transition Trust		1,984			2,470
Long-term debt to other financing trusts		545			545
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,193			5,340
Asset retirement obligations		3,890			3,780
Pension obligations		725			747
Non-pension postretirement benefit obligations		1,808			1,817
Spent nuclear fuel obligation		974			950
Regulatory liabilities		3,240			3,025
Mark-to-market derivative liabilities		301			78
Other		1,549			782

Total deferred credits and other liabilities		17,680			16,519

Total liabilities		34,047			34,225

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 674 and 670 shares outstanding at June 30, 2007 and December 31, 2006, respectively)		8,552			8,314
Treasury stock, at cost (13 and 13 shares held at June 30, 2007 and December 31, 2006, respectively)		(667	)		(630	)
Retained earnings		4,506			3,426
Accumulated other comprehensive loss, net		(1,220	)		(1,103	)

Total shareholders’ equity		11,171			10,007

Total liabilities and shareholders’ equity	$	45,305		$	44,319

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


											Accumulated
											Other			Total
	Issued		Common		Treasury			Retained			Comprehensive			Shareholders’
(In millions)	Shares		Stock		Stock			Earnings			Loss			Equity

Balance, December 31, 2006		683	$	8,314	$	(630	)	$	3,426		$	(1,103	)	$	10,007
Net income		—		—		—			1,393			—			1,393
Long-term incentive plan activity		4		238		—			—			—			238
Common stock purchases		—		—		(37	)		—			—			(37	)
Common stock dividends declared		—		—		—			(300	)		—			(300	)
Adoption of Financial Accounting Standards Board Interpretation No. 48 (FIN 48)		—		—		—			(13	)		—			(13	)
Other comprehensive loss, net of income taxes of $(43)		—		—		—			—			(117	)		(117	)

Balance, June 30, 2007		687	$	8,552	$	(667	)	$	4,506		$	(1,220	)	$	11,171

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2007			2006			2007			2006

Operating revenues
Operating revenues	$	1,813		$	1,100		$	3,655		$	2,132
Operating revenues from affiliates		828			1,114			1,689			2,302

Total operating revenues		2,641			2,214			5,344			4,434

Operating expenses
Purchased power		538			418			1,131			781
Fuel		436			425			907			1,036
Operating and maintenance		545			362			1,106			955
Operating and maintenance from affiliates		73			78			151			153
Depreciation and amortization		65			72			133			139
Taxes other than income		47			41			88			84

Total operating expenses		1,704			1,396			3,516			3,148

Operating income		937			818			1,828			1,286

Other income and deductions
Interest expense		(31	)		(40	)		(66	)		(81	)
Interest expense to affiliates, net		—			—			—			(1	)
Equity in (losses) earnings of investments		(1	)		(1	)		1			(5	)
Other, net		22			14			54			20

Total other income and deductions		(10	)		(27	)		(11	)		(67	)

Income from continuing operations before income taxes		927			791			1,817			1,219
Income taxes		349			294			684			454

Income from continuing operations		578			497			1,133			765

Discontinued operations
Gain on disposal of discontinued operations (net of taxes of $0, $2, $2 and $2 for the three and six months ended June 30, 2007 and 2006, respectively)		—			3			5			3

Income from discontinued operations, net		—			3			5			3

Net income		578			500			1,138			768

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost related to non-pension postretirement benefit plans		(1	)		—			(1	)		—
Finalization of year-end valuation		5			—			5			—
Change in unrealized gain (loss) on cash-flow hedges		208			141			(214	)		232
Unrealized gain (loss) on marketable securities		28			(13	)		37			15

Other comprehensive income (loss)		240			128			(173	)		247

Comprehensive income	$	818		$	628		$	965		$	1,015

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months
	Ended
	June 30,
(In millions)	2007			2006

Cash flows from operating activities
Net income	$	1,138		$	768
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		460			464
Deferred income taxes and amortization of investment tax credits		(12	)		81
Net realized and unrealized mark-to-market transactions		109			(37	)
Other non-cash operating activities		130			(56	)
Changes in assets and liabilities
Accounts receivable		(244	)		79
Receivables from and payables to affiliates, net		253			6
Inventories		3			10
Accounts payable, accrued expenses and other current liabilities		(85	)		(237	)
Counterparty collateral asset		(231	)		178
Counterparty collateral liability		(267	)		5
Income taxes		29			38
Pension and non-pension postretirement benefit contributions		(22	)		(14	)
Other assets and liabilities		(146	)		(218	)

Net cash flows provided by operating activities		1,115			1,067

Cash flows from investing activities
Capital expenditures		(550	)		(512	)
Proceeds from nuclear decommissioning trust fund sales		2,268			2,554
Investment in nuclear decommissioning trust funds		(2,402	)		(2,706	)
Proceeds from sale of investments		95			—
Changes in Exelon intercompany money pool contributions		13			—
Change in restricted cash		1			1
Other investing activities		(9	)		(3	)

Net cash flows used in investing activities		(584	)		(666	)

Cash flows from financing activities
Change in short-term debt		39			(2	)
Changes in Exelon intercompany money pool borrowings		—			(92	)
Distribution to member		(665	)		(322	)
Contribution from member		—			5
Other financing activities		1			—

Net cash flows used in financing activities		(625	)		(411	)

Decrease in cash and cash equivalents		(94	)		(10	)
Cash and cash equivalents at beginning of period		128			34

Cash and cash equivalents at end of period	$	34		$	24

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
(In millions)	2007		2006

ASSETS
Current assets
Cash and cash equivalents	$	34	$	128
Restricted cash and investments		1		2
Accounts receivable, net
Customer		802		575
Other		188		122
Mark-to-market derivative assets		749		1,408
Receivable from affiliates		214		437
Inventories, net
Fossil fuel		123		127
Materials and supplies		344		335
Contributions to Exelon intercompany money pool		—		13
Prepayments and other current assets		504		286

Total current assets		2,959		3,433

Property, plant and equipment, net		7,720		7,514
Deferred debits and other assets
Nuclear decommissioning trust funds		6,777		6,415
Investments		36		115
Mark-to-market derivative assets		210		171
Prepaid pension asset		978		996
Other		355		265

Total deferred debits and other assets		8,356		7,962

Total assets	$	19,035	$	18,909

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
(In millions)	2007		2006

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Short-term borrowings	$	39	$	—
Long-term debt due within one year		12		12
Accounts payable		762		899
Mark-to-market derivative liabilities		628		1,003
Payables to affiliates		30		—
Accrued expenses		493		496
Deferred income taxes		31		142
Other		133		362

Total current liabilities		2,128		2,914

Long-term debt		1,778		1,778
Deferred credits and other liabilities
Asset retirement obligations		3,709		3,602
Pension obligation		32		37
Non-pension postretirement benefit obligations		567		538
Spent nuclear fuel obligation		974		950
Deferred income taxes and unamortized investment tax credits		1,418		1,380
Payables to affiliates		2,048		1,911
Mark-to-market derivative liabilities		298		77
Other		343		238

Total deferred credits and other liabilities		9,389		8,733

Total liabilities		13,295		13,425

Commitments and contingencies
Minority interest of consolidated subsidiary		1		1
Member’s equity
Membership interest		3,267		3,267
Undistributed earnings		2,229		1,800
Accumulated other comprehensive income, net		243		416

Total member’s equity		5,739		5,483

Total liabilities and member’s equity	$	19,035	$	18,909

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN MEMBER’S EQUITY

(Unaudited)


						Accumulated
						Other			Total
	Membership		Undistributed			Comprehensive			Member’s
(In millions)	Interest		Earnings			Income			Equity

Balance, December 31, 2006	$	3,267	$	1,800		$	416		$	5,483
Net income		—		1,138			—			1,138
Distribution to member		—		(665	)		—			(665	)
Adoption of FIN 48		—		(44	)		—			(44	)
Other comprehensive loss, net of income taxes of $(76)		—		—			(173	)		(173	)

Balance, June 30, 2007	$	3,267	$	2,229		$	243		$	5,739

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2007			2006			2007			2006

Operating revenues
Operating revenues	$	1,419		$	1,450		$	2,907		$	2,874
Operating revenues from affiliates		1			3			4			6

Total operating revenues		1,420			1,453			2,911			2,880

Operating expenses
Purchased power		508			81			1,096			172
Purchased power from affiliate		330			685			710			1,456
Operating and maintenance		221			165			415			329
Operating and maintenance from affiliates		45			53			95			105
Depreciation and amortization		109			106			217			205
Taxes other than income		76			71			157			152

Total operating expenses		1,289			1,161			2,690			2,419

Operating income		131			292			221			461

Other income and deductions
Interest expense		(73	)		(58	)		(141	)		(114	)
Interest expense to affiliates, net		(14	)		(19	)		(29	)		(39	)
Equity in losses of unconsolidated affiliates		(2	)		(3	)		(4	)		(5	)
Other, net		5			1			7			1

Total other income and deductions		(84	)		(79	)		(167	)		(157	)

Income before income taxes		47			213			54			304
Income taxes		18			86			21			123

Net income		29			127			33			181

Other comprehensive income, net of income taxes
Change in unrealized gain on cash-flow hedges		1			—			4			—
Unrealized gain on marketable securities		1			—			1			—

Other comprehensive income		2			—			5			—

Comprehensive income	$	31		$	127		$	38		$	181

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2007			2006

Cash flows from operating activities
Net income	$	33		$	181
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		217			205
Deferred income taxes and amortization of investment tax credits		14			(25	)
Net realized and unrealized mark-to-market and hedging transactions		—			7
Other non-cash operating activities		107			72
Changes in assets and liabilities:
Accounts receivable		(38	)		24
Inventories		10			(8	)
Accounts payable, accrued expenses and other current liabilities		84			(3	)
Receivables from and payables to affiliates, net		(129	)		10
Income taxes		24			100
Change in restricted cash		(42	)		—
Pension and non-pension postretirement benefit contributions		(3	)		(4	)
Other assets and liabilities		(93	)		(7	)

Net cash flows provided by operating activities		184			552

Cash flows from investing activities
Capital expenditures		(559	)		(465	)
Change in restricted cash		(1	)		(1	)
Other investing activities		11			5

Net cash flows used in investing activities		(549	)		(461	)

Cash flows from financing activities
Changes in short-term debt		415			(120	)
Issuance of long-term debt		286			320
Retirement of long-term debt		(146	)		(1	)
Retirement of long-term debt to ComEd Transitional Funding Trust		(180	)		(174	)
Changes in Exelon intercompany money pool borrowings		—			(140	)
Contributions from parent		—			23
Other financing activities		—			(3	)

Net cash flows provided by (used in) financing activities		375			(95	)

Increase (decrease) in cash and cash equivalents		10			(4	)
Cash and cash equivalents at beginning of period		35			38

Cash and cash equivalents at end of period	$	45		$	34

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
(In millions)	2007		2006

ASSETS
Current assets
Cash and cash equivalents	$	45	$	35
Restricted cash		43		—
Accounts receivable, net
Customer		750		740
Other		110		62
Inventories, net		72		83
Deferred income taxes		27		29
Receivables from affiliates		—		18
Regulatory assets		104		—
Other		36		40

Total current assets		1,187		1,007

Property, plant and equipment, net		10,827		10,457
Deferred debits and other assets
Regulatory assets		519		532
Investments		46		44
Investments in affiliates		12		20
Goodwill		2,641		2,694
Receivables from affiliates		1,873		1,774
Prepaid pension asset		895		914
Other		466		332

Total deferred debits and other assets		6,452		6,310

Total assets	$	18,466	$	17,774

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,			December 31,
(In millions)	2007			2006

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	475		$	60
Long-term debt due within one year		418			147
Long-term debt to ComEd Transitional Funding Trust due within one year		273			308
Accounts payable		286			203
Accrued expenses		281			467
Payables to affiliates		96			219
Customer deposits		116			114
Other		80			82

Total current liabilities		2,025			1,600

Long-term debt		3,304			3,432
Long-term debt to ComEd Transitional Funding Trust		170			340
Long-term debt to other financing trusts		361			361
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,026			2,310
Asset retirement obligations		160			156
Non-pension postretirement benefit obligations		205			176
Regulatory liabilities		2,933			2,824
Other		947			277

Total deferred credits and other liabilities		6,271			5,743

Total liabilities		12,131			11,476

Commitments and contingencies
Shareholders’ equity
Common stock		1,588			1,588
Other paid-in capital		4,906			4,906
Retained deficit		(161	)		(193	)
Accumulated other comprehensive income (loss), net		2			(3	)

Total shareholders’ equity		6,335			6,298

Total liabilities and shareholders’ equity	$	18,466		$	17,774

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)


										Accumulated
			Other		Retained			Retained		Other			Total
	Common		Paid-In		Deficit			Earnings		Comprehensive			Shareholders’
(In millions)	Stock		Capital		Unappropriated			Appropriated		Income (Loss)			Equity

Balance, December 31, 2006	$	1,588	$	4,906	$	(1,632	)	$	1,439	$	(3	)	$	6,298
Net income		—		—		33			—		—			33
Appropriation of retained earnings for future dividends		—		—		(21	)		21		—			—
Adoption of FIN 48		—		—		(1	)		—		—			(1	)
Other comprehensive income, net of income taxes of $3		—		—		—			—		5			5

Balance, June 30, 2007	$	1,588	$	4,906	$	(1,621	)	$	1,460	$	2		$	6,335

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2007			2006			2007			2006

Operating revenues
Operating revenues	$	1,266		$	1,144		$	2,762		$	2,546
Operating revenues from affiliates		3			4			7			8

Total operating revenues		1,269			1,148			2,769			2,554

Operating expenses
Purchased power		72			72			136			142
Purchased power from affiliate		497			429			977			845
Fuel		86			76			385			402
Operating and maintenance		119			109			238			225
Operating and maintenance from affiliates		27			32			56			64
Depreciation and amortization		185			172			370			343
Taxes other than income		71			53			142			117

Total operating expenses		1,057			943			2,304			2,138

Operating income		212			205			465			416

Other income and deductions
Interest expense		(24	)		(18	)		(44	)		(35	)
Interest expense to affiliates, net		(40	)		(49	)		(82	)		(101	)
Equity in losses of unconsolidated affiliates		(2	)		(2	)		(4	)		(6	)
Other, net		5			2			10			5

Total other income and deductions		(61	)		(67	)		(120	)		(137	)

Income before income taxes		151			138			345			279
Income taxes		55			45			121			93

Net income		96			93			224			186
Preferred stock dividends		1			1			2			2

Net income on common stock	$	95		$	92		$	222		$	184

Comprehensive income, net of income taxes
Net income	$	96		$	93		$	224		$	186

Other comprehensive loss, net of income taxes
Change in net unrealized loss on cash-flow hedges		—			(1	)		—			(1	)

Other comprehensive loss		—			(1	)		—			(1	)

Comprehensive income	$	96		$	92		$	224		$	185

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended June 30,
(In millions)	2007			2006

Cash flows from operating activities
Net income	$	224		$	186
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		370			343
Deferred income taxes and amortization of investment tax credits		(117	)		(138	)
Other non-cash operating activities		47			61
Changes in assets and liabilities:
Accounts receivable		(60	)		73
Inventories		55			9
Accounts payable, accrued expenses and other current liabilities		(46	)		(123	)
Receivables from and payables to affiliates, net		(32	)		27
Income taxes		114			142
Pension and non-pension postretirement benefit contributions		(11	)		(10	)
Other assets and liabilities		(77	)		(20	)

Net cash flows provided by operating activities		467			550

Cash flows from investing activities
Capital expenditures		(161	)		(164	)
Changes in Exelon intercompany money pool contributions		—			8
Change in restricted cash		3			(1	)
Other investing activities		(2	)		—

Net cash flows used in investing activities		(160	)		(157	)

Cash flows from financing activities
Issuance of long-term debt		179			6
Retirement of long-term debt to PECO Energy Transition Trust		(354	)		(248	)
Change in short-term debt		27			7
Changes in Exelon intercompany money pool borrowings		(45	)		—
Dividends paid on common and preferred stock		(278	)		(253	)
Contributions from parent		165			83

Net cash flows used in financing activities		(306	)		(405	)

Increase (decrease) in cash and cash equivalents		1			(12	)
Cash and cash equivalents at beginning of period		29			37

Cash and cash equivalents at end of period	$	30		$	25

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,		December 31,
(In millions)	2007		2006

ASSETS
Current assets
Cash and cash equivalents	$	30	$	29
Restricted cash		1		4
Accounts receivable, net
Customer		480		426
Other		69		79
Inventories, net
Gas		116		173
Materials and supplies		15		13
Deferred income taxes		32		25
Prepaid utility taxes		89		—
Other		13		13

Total current assets		845		762

Property, plant and equipment, net		4,735		4,651
Deferred debits and other assets
Regulatory assets		3,603		3,896
Investments		24		21
Investments in affiliates		61		64
Receivable from affiliate		192		151
Other		473		228

Total deferred debits and other assets		4,353		4,360

Total assets	$	9,933	$	9,773

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
(In millions)	2007			2006

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	122		$	95
Borrowings from Exelon intercompany money pool		—			45
Long-term debt due within one year		450			—
Long-term debt to PECO Energy Transition Trust due within one year		236			273
Accounts payable		169			175
Accrued expenses		160			121
Payables to affiliates		171			203
Customer deposits		58			50
Other		25			16

Total current liabilities		1,391			978

Long-term debt		1,200			1,469
Long-term debt to PECO Energy Transition Trust		1,814			2,131
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,682			2,601
Asset retirement obligations		22			21
Non-pension postretirement benefit obligations		287			283
Regulatory liabilities		263			151
Other		147			146

Total deferred credits and other liabilities		3,401			3,202

Total liabilities		7,990			7,964

Commitments and contingencies
Shareholders’ equity
Common stock		2,223			2,223
Preferred stock		87			87
Receivable from parent		(925	)		(1,090	)
Retained earnings		553			584
Accumulated other comprehensive income, net		5			5

Total shareholders’ equity		1,943			1,809

Total liabilities and shareholders’ equity	$	9,933		$	9,773

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)


											Accumulated
					Receivable						Other		Total
	Common		Preferred		from			Retained			Comprehensive		Shareholders’
(In millions)	Stock		Stock		Parent			Earnings			Income		Equity

Balance, December 31, 2006	$	2,223	$	87	$	(1,090	)	$	584		$	5	$	1,809
Net income		—		—		—			224			—		224
Common stock dividends		—		—		—			(276	)		—		(276	)
Preferred stock dividends		—		—		—			(2	)		—		(2	)
Repayment of receivable from parent		—		—		165			—			—		165
Adoption of FIN 48		—		—		—			23			—		23

Balance, June 30, 2007	$	2,223	$	87	$	(925	)	$	553		$	5	$	1,943

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)


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

Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the generation, energy delivery and other businesses discussed below. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail sales operations of Exelon Generation Company, LLC (Generation). The energy delivery businesses include the purchase and regulated retail and wholesale sale of electricity and the provision of distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois, including the City of Chicago, and by PECO Energy Company (PECO) in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

Exelon’s consolidated financial statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Exelon or one of its subsidiaries as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.

Exelon owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred stock. Exelon has reflected the third-party interests in ComEd as minority interests and PECO’s preferred stock as preferred securities of subsidiaries in its consolidated financial statements.

Generation’s consolidated financial statements include the accounts of its subsidiaries, including AmerGen Energy Company, LLC (AmerGen) and Exelon Energy Company, LLC. All intercompany transactions have been eliminated.

ComEd’s consolidated financial statements include the accounts of ComEd and Commonwealth Edison Company of Indiana, Inc. All intercompany transactions have been eliminated.

PECO’s consolidated financial statements include the accounts of PECO and its subsidiaries, including ExTel Corporation, LLC, Adwin Realty Company and PECO Wireless, LP. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of June 30, 2007 and 2006 and for the three and six months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO (collectively, Registrants), include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2006 Consolidated Balance Sheets were taken from audited financial statements. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (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 Consolidated Financial Statements of Exelon, Generation, ComEd and PECO included in ITEM 8 of their 2006 Annual Report on Form 10-K.


2.	Discontinued Operations (Exelon and Generation)

As discussed in Note 4 — Acquisitions and Dispositions, on January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc. (Sithe). In addition, during 2003 and 2004, Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises). As a result, the results of operations and any gain or loss on the sale of these entities are presented as discontinued operations for the three and six months ended June 30, 2007 and 2006 within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations and Comprehensive Income.

For the three and six months ended June 30, 2007, Exelon’s Consolidated Statements of Operations and Comprehensive Income included $1 million of loss and $4 million of income, respectively, from discontinued operations related to Enterprises. There was no significant activity related to the discontinued operations for Enterprises during the three and six months ended June 30, 2006.

For the six months ended June 30, 2007, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income included $5 million (after-tax) gain on disposal of discontinued operations related primarily to Sithe, resulting from a settlement agreement between a subsidiary of Sithe, the Pennsylvania Attorney General’s Office and the Pennsylvania Department of Revenue regarding a previously disputed tax position asserted for the 2000 tax year. There was no significant activity related to the discontinued operations for Sithe during the three months ended June 30, 2007. For the three and six months ended June 30, 2006, Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income included $3 million of income (after-tax) from discontinued operations related to Sithe, which represented an adjustment to the gain on sale as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved. See Note 4 — Acquisitions and Dispositions for additional information regarding Generation’s sale of its investment in Sithe.

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

FIN 48

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” FIN 48 applies to all income tax positions taken on previously filed tax returns or expected to be taken on a future tax return. FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded.

Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold for purposes of applying FIN 48. Therefore, if it can be established that the only uncertainty is when an item is taken on a tax return, such positions have satisfied the recognition step for purposes of FIN 48 and uncertainty related to timing should be assessed as part of measurement. FIN 48 also requires that the amount of interest expense and income to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return.

FIN 48 was effective for the Registrants as of January 1, 2007. The change in net assets as a result of applying this pronouncement was considered a change in accounting principle with the cumulative effect of the change required to primarily be treated as an adjustment to the opening balance of retained earnings (deficit). Adjustments to goodwill or regulatory accounts associated with the implementation of FIN 48 were based on other applicable accounting standards. See Note 10 — Income Taxes for additional information regarding the adoption of FIN 48.

FIN 48 prescribes that a company shall recognize the benefit of a tax position when it is effectively settled. The FASB issued FASB Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48”, in May 2007 to provide guidance on how companies should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The Registrants contemplated the provisions of FSP FIN 48-1 upon the initial adoption of FIN 48.

SFAS No. 157

In September 2006, the FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements but does not change the requirements to apply fair value in existing accounting standards. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. SFAS No. 157 will be effective for the Registrants as of January 1, 2008, and the Registrants are currently assessing the impact that SFAS No. 157 may have on their financial statements.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 gives companies the option of applying at specified election dates fair value accounting to certain financial instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and losses on those items in earnings at each subsequent reporting date. SFAS No. 159 also prescribes presentation and disclosure requirements for assets and liabilities that are measured at fair value pursuant to this standard and pursuant to the guidance in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). SFAS No. 159 will be effective for the Registrants as of January 1, 2008, and the Registrants are currently assessing the impact SFAS No. 159 may have on their financial statements.

FSP FIN 39-1

In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). This pronouncement amends FIN 39, “Offsetting of Amounts Related to Certain Contracts”, to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP FIN 39-1 will be effective for the Registrants as of January 1, 2008. The effects of applying this pronouncement shall be recognized as a change in accounting principle through retrospective application for all financial statements presented unless it is impracticable to do so. The Registrants are currently assessing whether to elect the accounting policies prescribed by FSP FIN 39-1 which, if elected, would not impact net income.


4.	Acquisitions and Dispositions (Exelon and Generation)

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, Exelon recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. These indemnifications and guarantees are being accounted for under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others”. The remaining exposures covered by these indemnities are anticipated to expire in 2007 and beyond. As of June 30, 2007, Exelon’s accrued liabilities related to these indemnifications and guarantees were $43 million. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $175 million at June 30, 2007.

See Note 2 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further discussion of Generation’s sale of its investment in Sithe.

Sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (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 guaranty 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 guaranty that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guaranty is $95 million. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guaranty are anticipated to expire in the second half of 2008 and beyond.


5.	Regulatory Issues (Exelon, Generation, ComEd and PECO)

The legislatively mandated transition and rate freeze period in Illinois ended at the close of 2006. Associated with the end of this rate freeze, ComEd has been engaged in various regulatory proceedings to establish rates for the post-2006 period, which are more fully described below. In view of the rate increases following the expiration of the rate freeze, various Illinois legislative attempts, as more fully described below, have been made to roll back and freeze ComEd’s rates for an additional period or to control the rate at which the rate increases are phased in or impose a tax on the ownership or operation of electric generating facilities. ComEd and Generation have been engaged in discussions with Illinois legislative leaders and others to address concerns about higher electric bills in Illinois without a rate roll-back and rate freeze, a generation tax or other similar legislation. Those discussions successfully concluded on July 24, 2007, when ComEd, Generation, and other utilities and generators in Illinois reached an oral agreement with representatives of the Illinois state government and submitted a confirming letter to the Speaker of the Illinois House of Representatives, the President of the Illinois Senate, the minority leaders of the Illinois House and Senate, and the Attorney General of the State of Illinois, more fully described below.

Rate Freeze, Generation Tax and Other Proposed Legislation (Exelon, Generation and ComEd). The increases in ComEd’s 2007 rates reflect the pass-through of ComEd’s costs of procuring electricity for customers, significant capital investment that ComEd has made in distribution assets, and changes in ComEd’s operating costs.

ComEd estimates that its average residential customer is experiencing an annual increase of approximately 24% in its electric bills; however, some customer increases have been larger. Customers of certain other Illinois utilities have experienced much more significant increases in their bills.

Since March 2007, various bills have been proposed by the Illinois House of Representatives and Senate in an attempt to address the higher electric bills experienced in the state of Illinois since the expiration of the rate freeze at the end of 2006. The significant components of the proposed legislation would have required the following:


	•	A rollback of electricity rates to rates in effect in 2006, effective for at least one year. Furthermore, ComEd would have been required to provide refunds, with interest, of charges collected from residential customers in excess of those rolled-back rates since January 1, 2007.

	•	A limit to rate increases for all bundled service customers for at least one year, and until 2010 in other versions of the legislation.

	•	A tax of $70,000 for each megawatt of nameplate capacity on certain electric generating facilities located in Illinois including those owned by Generation.

	•	Establishment of a generation tax and a fund from the proceeds of the generation tax to be used to reimburse ComEd and other Illinois utilities for rate refunds and also to refund ComEd and other Illinois utilities for differences between 2007 and 2006 rates prior to July 1, 2008.

	•	ComEd would be required to supply all residential and small commercial and industrial customers who have central air conditioning with direct load control devices. ComEd would not be allowed to recover the cost of these devices through rates, but only from the generation tax fund.

	•	Beginning in 2009, no electric utility, including ComEd, could have been owned by a company, such as Exelon, which also participates, as Exelon does through Generation, in power generation or marketing.

	•	Require electric utilities, including ComEd, to remove themselves from participation in regional transmission organizations, including PJM Interconnection, LLC (PJM).

On April 23, 2007, ComEd announced the implementation of a new $64 million rate relief package to be provided to ComEd customers most affected by electricity rate increases. Inclusive of ComEd’s funding of its Customers’ Affordable Reliable Energy (CARE) initiative, ComEd anticipates that its customer rate relief programs will provide benefits to its customers of approximately $44 million in 2007 and approximately $10 million in additional funds per year during 2008 and 2009. During the six months ended June 30, 2007, ComEd recorded a reduction in operating revenues of $19 million and a charge to operating and maintenance expense of $8 million associated with the 2007 portion of this announced program. During the six months ended June 30, 2007, ComEd has credited approximately $18 million to its customers.

On July 24, 2007, following extensive discussions with legislative leaders in Illinois, ComEd, Generation, and other utilities and generators in Illinois reached an oral agreement (the Settlement) with various representatives from the State of Illinois concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. The Settlement was recorded in a confirming letter (the Letter) to the Speaker of the Illinois House of Representatives, the President of the Illinois Senate, the minority leaders of the Illinois House and Senate, and the Attorney General of the State of Illinois (the Attorney General) from ComEd, Generation, and other utilities and generators in Illinois.

The Settlement will be effective only upon enactment of proposed legislation (Proposed Legislation), which was drafted as part of the Settlement and attached as an exhibit to the Letter. If it becomes effective, the Settlement and the Proposed Legislation would provide for the following, among other things:


	•	Illinois electric utilities, their affiliates, and generators of electricity in Illinois would make voluntary contributions of approximately $1 billion over a period of four years to programs that would provide rate relief to Illinois electricity customers and funding for the new Illinois Power Agency to be created by the Proposed Legislation. Exelon has committed to contributing approximately $800 million to rate relief programs over four years and funding for the Illinois Power Agency, in addition to approximately $11 million of rate relief credits provided by ComEd prior to June 14, 2007 under rate relief programs previously announced. ComEd would continue executing upon its $64 million rate relief package announced April 23, 2007, as described above. Generation would contribute an aggregate of up to $747 million, of which $435 million would be available to reimburse ComEd for rate relief programs for ComEd customers, and $307.5 million would be available for rate relief programs for customers of other Illinois utilities, and $4.5 million would be available for funding operations of the Illinois Power Agency. Of the $800 million to be contributed to rate relief by Generation and ComEd, $459 million will be contributed in 2007, $222 million will be contributed in 2008, $105 million will be contributed in 2009, and $14 million will be contributed in 2010.

	•	In the event that the Illinois General Assembly passes legislation prior to August 1, 2011 that freezes or reduces electric rates or imposes a generation tax on any party to the Settlement, the contributors to the rate relief funds would be allowed to terminate their funding commitments and may recover any undisbursed funds set aside for rate relief.

	•	The existing contracts resulting from the procurement auction in 2006 will be honored. As those contracts expire, procurement will be made pursuant to a horizontal, sealed bid procurement process to establish long-term market-based contracts.

	•	To fulfill a requirement of the Settlement, ComEd and Generation have entered into a five-year financial swap arrangement, the effect of which will cause ComEd to pay fixed prices and cause Generation to pay a market price for a portion of ComEd’s load. The financial terms cover energy costs only, not capacity or ancillary services. The contract has been fully executed but is not effective until the Proposed Legislation contemplated by the Settlement is effective.


	•	The contract is designed to dovetail with ComEd’s remaining auction contracts for energy, increasing in volume as the contracts expire.

	•	The contract volumes will be 1,000 MW for the period from June 2008 through May 2009, 2,000 MW for the period from June 2009 through May 2010, and 3,000 MW in each of the periods June 2010 through May 2011, June 2011 through May 2012, and June 2012 through May 2013.

	•	This arrangement will be deemed prudent and ComEd will receive full cost recovery in rates.


	•	A new state agency, known as the Illinois Power Agency (the Agency), would be created and authorized to design annual five-year electricity supply portfolio plans for electric utilities and administer a competitive procurement process for utilities to procure the electricity supply resources identified in the supply portfolio plans. The Agency, under certain conditions, would also be authorized to construct generation and co-generation facilities that use indigenous coal or renewable resources, or both, to supply electricity at cost to municipal electric systems and rural electric cooperatives. The Agency’s operations will be funded from fees


		and bond proceeds and the interest on $25 million of the $1 billion customer rate relief package to be contributed to the Illinois Power Agency Trust Fund.


	•	The ability of utilities to engage in divestiture and other restructuring transactions without prior Illinois Commerce Commission (ICC) approval would be extended until all classes of tariffed service are declared competitive.

	•	The Proposed Legislation would also declare that the 400 kw and above customer classes of ComEd are competitive and would establish an expedited procedure for finding customer classes with demands of 100 kw or greater but less than 400 kw are competitive.

	•	Until at least June 30, 2022, the state would not prohibit an electric utility from maintaining its membership in a Federal Energy Regulatory Commission (FERC) approved regional transmission organization chosen by the utility.

	•	ComEd would be required to provide tariffed service to condominium associations at rates that do not exceed rates offered to residential customers.

	•	Utilities would be prohibited from terminating electric service to a residential electric space heat customer due to nonpayment before September 1, 2007 or between December 1 of any year and March 1 of the following year.

	•	Electric utilities would be required to use cost-effective energy efficiency and demand response resources to meet defined incremental annual program energy and demand savings goals. These goals generally call for reductions in delivered energy from the prior year for energy efficiency programs and for reductions in peak demand from the prior year for eligible customers. The goals would be subject to rate impact caps each year. Utilities would be allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. Failure to comply with the energy efficiency and demand response requirements in the Proposed Legislation would result in ComEd being subject to penalties and other charges.

	•	The procurement plans developed by the Illinois Power Agency and implemented by electric utilities must include cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers by June 1, 2008, increasing to 10% by June 1, 2015, with a goal of 25% by June 1, 2025. Utilities would be allowed to pass-through any costs or savings from the procurement of these renewable resources.

In connection with the Settlement, ComEd, Generation, the Illinois Attorney General, and other Illinois utilities have entered into a release and settlement agreement releasing and dismissing with prejudice all litigation, claims and regulatory proceedings and appeals relating to or arising out of the procurement of power, including ICC and FERC proceedings relating to the procurement of power. The release and settlement agreement is contingent on the enactment of the Proposed Legislation.

In connection with the Settlement, Generation, ComEd and the Illinois Attorney General have entered into a Rate Relief Funding Agreement dated July 24, 2007, pursuant to which ComEd has contractually committed itself to the rate relief contemplated by the Settlement and Generation has contractually committed itself to reimburse ComEd for up to $435 million of costs incurred by ComEd in connection with the rate relief contemplated by the Settlement. In addition, Generation, the Illinois utilities owned by Ameren Corporation (Ameren), and the Illinois Attorney General have entered into a separate Rate Relief Funding Agreement dated July 24, 2007, pursuant to which the Ameren Utilities have contractually committed themselves to the rate relief contemplated by the Settlement and Generation has contractually committed itself to reimburse the Ameren Utilities for up to $307.5 million of costs incurred by the Ameren Utilities in connection with the rate relief contemplated by the

Settlement. These funding commitments become effective only upon the enactment into law of the Proposed Legislation and will terminate if the Illinois General Assembly passes legislation prior to August 1, 2011 that freezes or reduces electric rates or imposes a generation tax on any party to the Settlement.

To become law in Illinois, legislation must be passed by the House and Senate and signed by the Governor of Illinois. There is no guarantee that the Proposed Legislation will be passed by the House and Senate and signed by the Governor.

Customers’ Affordable Reliable Energy (Exelon and ComEd). In July 2006, ComEd implemented CARE, an initiative to help customers prepare for electricity rate increases coming in 2007 after the expiration of the rate freeze in Illinois. In addition to the residential rate stabilization program discussed below, CARE includes a variety of energy efficiency, low-income and senior citizen programs to help mitigate the impacts of the rate increase on customers’ bills.

In the ICC’s December 20, 2006 order approving ComEd’s residential rate stabilization program (see below), the ICC also strongly encouraged, but did not require, ComEd to make contributions to environmental and customer assistance programs. On February 20, 2007, ComEd filed a letter with the ICC indicating its intent, if financially able to do so, to contribute $30 million over three years to CARE related programs. ComEd also stated that it did not intend to seek rate recovery of these amounts and thus did not believe that the ICC needed to investigate the programs.

Illinois Procurement Case and Related Proceedings (Exelon, Generation and ComEd). On February 25, 2005, ComEd made a filing with the ICC to seek regulatory approval of tariffs that would authorize ComEd to bill its customers for electricity costs incurred under a reverse-auction competitive bidding process (the Procurement Case). On October 17, 2005, ComEd and Exelon Generation jointly filed a request for a declaratory order at the FERC seeking approval of the reverse-auction competitive bidding process it planned to use for ComEd’s procurement of wholesale supplies of electricity. On December 16, 2005, FERC issued an order holding that the proposed competitive bidding process satisfied FERC’s criteria for a competitive process and that Generation would be eligible for market-based rate sales to ComEd under the terms of the auction. On May 1, 2006, FERC denied the Illinois Attorney General’s request for rehearing of that order, and the Attorney General filed a petition for review of the ICC’s decision in the United States Court of Appeals for the District of Columbia Circuit. That appeal will be dismissed with prejudice in connection with the Settlement when the Proposed Legislation becomes effective.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of electricity by ComEd after the end of the transition period. Various parties, including the Illinois Attorney General, ComEd and consumer representatives, appealed the ICC approval, but the Attorney General’s appeal will be dismissed with prejudice in connection with the Settlement if the Proposed Legislation becomes effective. The energy price that resulted from the first auction is fixed until June 2008. On December 6, 2006, the ICC staff released its report on the auction, which generally spoke favorably of the process and the outcome. The report recommended the continued use of the reverse-auction for future electric power procurement. However, the Proposed Legislation will establish a different process for procurement of electricity by Illinois utilities.

In March 2007, the Illinois Attorney General filed a complaint before FERC alleging that the prices to all suppliers resulting from the auction are unjust and unreasonable under the Federal Power Act and that the suppliers colluded in the course of the auction. The Illinois Attorney General has agreed that this complaint will be dismissed with prejudice in connection with the Settlement if the Proposed Legislation becomes effective. Additionally, on

March 28, 2007 and March 30, 2007, class action suits were filed in Illinois state court against ComEd and Generation as well as the other suppliers in the Illinois procurement auction, claiming that the suppliers manipulated the auction and that the resulting wholesale prices are unlawfully high. Exelon, Generation and ComEd cannot predict the outcome of these proceedings, but each believes the claims to be completely false and unsupported by requisite evidence, and each intends to vigorously oppose these claims.

Illinois Rate Case (Exelon and ComEd). On August 31, 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007 (Rate Case). The commodity component of ComEd’s rates was established by the reverse-auction process in accordance with the ICC rate order in the Procurement Case. ComEd proposed a revenue increase of $317 million. The ICC staff and several intervenors in the Rate Case, including the Illinois Attorney General, suggested and provided testimony that ComEd’s rates for delivery services should be reduced. On July 26, 2006, the ICC issued its order in the Rate Case which approved a delivery services revenue increase of approximately $8 million of the $317 million proposed revenue increase requested by ComEd. On December 20, 2006, the ICC issued an order on rehearing that increased the amount previously approved by approximately $74 million for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. It is unlikely the appeal will be resolved until the third quarter of 2007 at the earliest. In the event the order is ultimately changed, the changes are expected to be prospective only.

Illinois Rate Design Investigation (Exelon and ComEd). On March 2, 2007, the ICC voted to initiate investigations into ComEd’s and the Ameren utilities’ rate designs, particularly for residential and residential space-heating customers. The investigation was prompted by hearings before the Illinois House of Representatives Committee of the Whole that took place in February 2007, where House Representatives and customers spoke of extreme and unexpected rate increases that took effect January 2007. The vast majority of noted situations related to Ameren customers. The ICC specified that the investigation would not look to the overall level of rates, which has just recently been set, but only to the allocation among the various customer groups. The ICC has a schedule that contemplates a final order by September 2007, which would allow implementation of changes, if any, prior to the next winter heating season.

Original Cost Audit (Exelon and ComEd). In the Rate Case, the ICC ordered an “original cost” audit of ComEd’s distribution assets. The ICC order did not find that any portion of ComEd’s delivery service assets should be disallowed because it was unreasonable in amount, imprudently incurred or not used and useful. The ICC rate order does not provide for a new review of these issues but instead provides that the ICC-appointed auditors determine whether the costs of ComEd’s distribution assets were properly recorded on ComEd’s financial statements at their original costs. The result of this audit will be addressed through a separately docketed proceeding. The original cost audit report is expected to be finalized in 2007 with an ICC proceeding to follow the issuance of the report. This proceeding may extend into 2008, and ComEd is unable to predict the results of this audit but at this time does not believe it has significant financial exposure related to the audit proceedings. These proceedings are not affected by the Settlement or the Proposed Legislation.

Renewable Energy Filings (Exelon and ComEd). On April 4, 2006, ComEd filed with the ICC a request for ICC approval to purchase and receive recovery of costs associated with the output of a portfolio of competitively procured wind resources of approximately 300 megawatts (MWs). On April 4, 2007, at the request of ComEd, the ICC terminated the proceeding.

Residential Rate Stabilization Program (Exelon and ComEd). On December 20, 2006, the ICC approved a program, proposed by ComEd, to mitigate the impact on ComEd’s residential customers of ComEd’s transition from almost a decade of reduced and frozen rates to rates that reflect the current cost of providing service. The program includes an “opt-in” feature to give residential customers the choice to participate in the program. The

program caps average annual residential rate increases at 10% in each of 2007, 2008 and 2009. For participating customers, costs that exceed the caps are deferred and recovered over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25% to partially cover ComEd’s costs of financing the program. If ComEd’s rate increases are less than the caps in 2008 and 2009, ComEd would begin to recover deferred amounts up to the caps with carrying costs. The program would terminate upon a force majeure event, upon a ComEd bankruptcy, or if ComEd’s senior secured credit ratings from two of three major credit rating agencies fall below investment grade. ComEd’s residential customers will have until August 2007 to choose to participate in the program. Reductions began to be reflected in April 2007 and are not retroactive. As of June 30, 2007, approximately 36,000 or 1% of ComEd’s residential customers have enrolled in the program and ComEd has deferred less than $1 million under this program. At this time, ComEd cannot predict the full extent of participation in the program or its financial effects.

City of Chicago Negotiations (Exelon and ComEd). ComEd has been in negotiations with the City of Chicago related to various components of its franchise agreement with the City of Chicago. As part of these discussions, ComEd may be able to resolve various outstanding issues relating to reliability, franchise obligations and other matters. As part of any agreement, ComEd may make payments to the City of Chicago, which may be material. No formal agreement has been reached.

Post-2006 Summary (Exelon, Generation and ComEd). Exelon and ComEd believe that the Settlement and the Proposed Legislation significantly reduce the risk that the Illinois General Assembly might pass rate roll back and freeze legislation or take other action that could have a material adverse effect on ComEd. However, the Proposed Legislation will not become law until it is enacted by the Illinois General Assembly and signed by the Governor.

Even if the Proposed Legislation becomes law, there are no assurances that the Illinois General Assembly will not consider a generation tax. Any assessed generation tax would have a negative financial impact on Generation. Exelon and Generation believe that the potential negative impact would include an increased provision for income taxes, and likewise a reduction in net income.

Similarly, there is no guarantee that rate roll-back, rate freeze legislation or other legislation that impairs ComEd’s ability to secure fair market prices will not be considered again by the Illinois General Assembly at a future date. If the price which ComEd is ultimately allowed to bill to customers for electricity is below ComEd’s cost to procure and deliver electricity, ComEd expects that it would suffer adverse consequences, which could be material. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, reduced earnings for Exelon and ComEd, further reduction of ComEd’s credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term energy procurement contracts, which may force ComEd to procure electricity at more volatile spot market prices, all of which could lead ComEd to seek protection through a bankruptcy filing. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the near term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible.

Additionally, if ComEd’s ability to recover its costs from customers through rates is significantly affected, all or a portion of ComEd’s business could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, which covers the accounting for the effects of rate regulation and would require Exelon and ComEd to eliminate the financial statement effects of regulation for the portion of ComEd’s business that ceases to meet the criteria. This would result in the elimination of all associated regulatory assets and liabilities that ComEd had recorded on its Consolidated Balance Sheets through the recording of a one-time extraordinary

gain on its Consolidated Statements of Operations and Comprehensive Income. At June 30, 2007, the income statement gain could have been as much as $2.3 billion (before taxes) at ComEd. In that event, Exelon would record an income statement gain in an equal amount related to ComEd’s regulatory assets and liabilities in addition to a charge against other comprehensive income of up to $1.2 billion (before taxes) related to Exelon’s regulatory assets and liabilities associated with its defined benefit postretirement plans and deferred taxes. Such eliminations could have the effect of producing income. If legislation extends an earnings-sharing provision that applied during the period in which rates were generally frozen, that provision requires that earnings in excess of a threshold be shared with customers. Finally, the impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which would be significant and partially offset, or exceed, the extraordinary gain discussed above. See Note 6 — Intangible Assets for further information related to ComEd’s goodwill. If ComEd were required to seek relief through a bankruptcy filing, there would be material adverse consequences to ComEd and Exelon, including, but not limited to: uncertainty in collection of receivables from ComEd by Exelon, including Exelon’s Business Services Company (BSC); significant legal and other costs associated with the bankruptcy filing; possible negative income tax consequences; and possible reduced ability to effectively administer and allocate the costs of the various Exelon-sponsored benefit plans.

Transmission Rate Case (Exelon and ComEd). On March 1, 2007, ComEd filed a request with FERC seeking approval to update its transmission rates and change the manner in which ComEd’s transmission rates are determined from fixed rates to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. Initial application of the formula would result in an increase of the revenues ComEd receives for transmission services, reflecting substantial investment in transmission-related plant since rates were based on costs from 2003. Between 2003 and the end of 2007, ComEd will have invested over $800 million in transmission-related plant to meet increasing demand and improve reliability. ComEd also requested incentive rate treatment for certain transmission projects. ComEd requested that the new transmission rates be effective as of May 2007. On June 5, 2007, FERC issued an order that conditionally approves ComEd’s proposal to implement a formula-based transmission rate effective as of May 1, 2007, but subject to refund, hearing procedures and conditions. The FERC order provides that further hearing and settlement procedures be conducted to determine the reasonableness of certain elements of ComEd’s formula-based rate. The issues set for hearing include ComEd proposed 11.70% base return on equity and various elements of ComEd’s rate base. The order denied ComEd’s request for incentive rate treatment on investment in two transmission projects and the inclusion of construction work in progress in ComEd’s rate base. The order directed ComEd to file a revised formula reflecting these findings within 30 days. The new rate will increase an average residential customer bill by about 1% and will result in an annual increase in the transmission revenue requirement of $116 million, although the rate increase is subject to further adjustment and refund depending on the outcome of the settlement and hearing procedures. The FERC order approved a 0.5% adder to the base return on equity for participating in a regional transmission organization. On July 5, 2007, ComEd filed a request for rehearing, asking FERC to reconsider the denial of incentive rate treatment on the two new transmission projects and the denial of construction work in progress in rate base and certain other elements of the June 5, 2007 order. Effective May 1, 2007, ComEd began billing customers based on the conditional FERC order. ComEd cannot predict how much of a transmission rate increase FERC may ultimately approve following the settlement and hearing procedures or when these proceedings will be completed. However, management believes that appropriate reserves have been established in the event that some portion of the transmission revenues are required to be refunded. The ultimate outcome of the FERC approval is uncertain, but ComEd does not believe ultimate resolution of this matter will be material to its results of operations or financial position.

Authorized Return on Rate Base (Exelon, ComEd and PECO). Under Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeded an established

threshold, one-half of the excess earnings was required to be refunded to customers. The threshold rate of return on common equity was based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (20 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd’s threshold included ComEd’s net income calculated in accordance with GAAP and reflected the amortization of regulatory assets. Under Illinois statute, any impairment of goodwill would have had no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. ComEd did not trigger the earnings sharing provision through 2006. With the end of the transition and rate freeze period, in its December 20, 2006 order the ICC authorized a return on the 2005 test year distribution rate base of 8.01% for ComEd starting in 2007. During the first quarter of 2007, ComEd filed a transmission rate case with FERC in which it requested a weighted average debt and equity return on transmission rate base of 9.87% as determined by a formula-based rate calculation as discussed above.

PECO’s transition period included caps for its electric transmission and distribution rates that expired on December 31, 2006 and continues to include caps on generation rates that will expire on December 31, 2010 pursuant to legislation enacted in Pennsylvania. The distribution and transmission components of PECO’s rates will continue to be regulated subsequent to its transition period. PECO’s most recently approved return on electric rate base was 11.23% (approved in 1990). PECO’s gas rates are currently not subject to caps and its most recently authorized return on gas rate base was 11.45% (approved in 1988).

Through and Out (T&O) Rates and Seams Elimination Charge/Cost Adjustment/Assignment (SECA) (Exelon, ComEd and PECO). In November 2004, FERC issued two orders authorizing ComEd and PECO to recover amounts for a limited time during a specified transitional period as a result of the elimination of T&O rates for transmission service scheduled out of, or across, their respective transmission systems and ending within territories of PJM or Midwest Independent Transmission System Operator (MISO). T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as SECA, were collected from load-serving entities and paid to transmission owners within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As load-serving entities, ComEd and PECO were also required to pay SECA rates during the transitional period based on the benefits they received from the elimination of T&O rates of other transmission owners within PJM and MISO. Since the inception of the SECA rates in December 2004, ComEd has recorded approximately $49 million of SECA collections net of SECA charges, while PECO has recorded $11 million of SECA charges net of SECA collections. Management of each of ComEd and PECO believes that appropriate reserves have been established in the event that some portion of SECA collections are required to be refunded. A hearing was held in May 2006 and the administrative law judge (ALJ) issued an Initial Decision on August 10, 2006. The ALJ’s Initial Decision found that the transmission owners overstated their lost revenues in their compliance filings and the SECA rate design was flawed. Additionally, the ALJ recommended that the transmission owners should be ordered to refile their respective compliance filings related to SECA rates. ComEd and PECO have filed exceptions to the Initial Decision and FERC, on review, will determine whether or not to accept the ALJ’s recommendation. There is no scheduled date for FERC to act on this matter. Settlements have been reached with various parties. FERC has approved several of these settlements while others are still awaiting FERC approval. The ultimate outcome of the proceeding establishing SECA rates is uncertain, but ComEd and PECO do not believe ultimate resolution of this matter will be material to their results of operations or financial position.

PJM Transmission Rate Design (Exelon, ComEd and PECO). On July 13, 2006, the ALJ in the case issued an Initial Decision that recommends that FERC implement the postage stamp rate suggested by FERC staff, effective as of April 1, 2006, but also allows for the potential to phase in rate changes. On April 19, 2007, FERC issued its order on review of the ALJ’s decision. FERC held that PJM’s current rate design for existing matter facilities is just and reasonable and should not be changed. That is consistent with Exelon’s position in the case.

FERC also held that new facilities should be allocated under a different rate design. FERC held that new facilities 500 kilovolts (kV) and above should be socialized across the entire PJM footprint and that new facilities less than 500 kV should be allocated to the beneficiaries of the new facilities. FERC stated that PJM’s stakeholders should develop a standard method for allocating new transmission facilities lower than 500 kV. FERC’s decision on existing facilities leaves the status quo as to existing costs, which is substantially more favorable to Exelon than the ALJ’s decision as to existing facilities. In the short term, based on new transmission facilities approved by PJM, it is likely that socializing costs across PJM will reduce costs to PECO and increase costs to ComEd, but ComEd and PECO cannot estimate the longer-term impact on either company’s results of operations and cash flows, because of the uncertainties relating to what new facilities will be built and how costs of new facilities less than 500 kV will be allocated is uncertain. On May 21, 2007, Exelon and other parties filed requests for rehearing of FERC’s April 19, 2007 order. There is not a required deadline for FERC to act on the requests for rehearing and FERC’s decision also may be subject to review in the United States Court of Appeals. However, ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006 should be recoverable through retail rates in the absence of rate freeze or similar legislation. With the expiration of PECO’s transmission and distribution rate caps on December 31, 2006, PECO has the right to file with the Pennsylvania Public Utility Commission (PAPUC) for a change in retail rates to reflect the impact of any change in wholesale transmission rates.

Alternative Energy Filing (Exelon and PECO). In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that beginning in 2007, or at the end of an electric distribution company’s restructuring cost recovery period during which competitive transition charges or intangible transition charges are being recovered, certain percentages of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from certain alternative energy resources. In March 2007, PECO filed a request with the PAPUC for approval to acquire and bank up to 450,000 non-solar Tier I Alternative Energy Credits (equivalent to up to 240 megawatts (MWs) of electricity generated by wind) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance following the completion of its restructuring period. PECO has proposed that all of the costs it incurs in connection with such procurement prior to 2011 will be deferred as a regulatory asset with a return on the unamortized balance in accordance with the AEPS Act. Those costs, and PECO’s AEPS compliance costs incurred thereafter, would be recovered through a reconcilable ratemaking mechanism as contemplated by the AEPS Act. Pursuant to the AEPS Act all deferred costs will be recovered from customers in 2011. Additionally, all AEPS related costs incurred after 2010 are recoverable from customers on a full and current basis. On July 16, 2007, the AEPS Act was modified by House Bill (HB) 1203, as it is discussed in “Pennsylvania Regulatory Matters” below. The modifications do not affect PECO’s request filed with PAPUC for the acquiring and banking of Alternative Energy Credits or the proposed deferral of related costs.

Default Service Regulations (Exelon and PECO). On May 10, 2007, after completion of a two year rule making process, the PAPUC adopted final Default Supplier (Provider of Last Resort) regulations, an accompanying policy statement, and a price mitigation policy statement. The regulations allow for competitive procurement by distribution companies through auctions or Requests for Proposals, with full cost recovery and no retrospective prudence review. According to the policy statement, the PAPUC expects companies to procure power, on a customer-class basis, using contracts of varying expiration dates, and prefers contracts with a duration of one year or less, except for contracts for compliance with the AEPS Act. The PAPUC also expects companies to reconcile costs and adjust rates at least quarterly for most customers, but hourly or monthly for larger energy users. The PAPUC believes this combination will stimulate competition, send market-price signals and avoid price spikes following long periods of fixed, capped rates. The PAPUC also ordered the elimination of (1) declining-block rates, while allowing rates to be phased out if the resulting rate increase is greater than 25%; and (2) demand charges for large customers, while entertaining requests to retain those charges on a case-by-case basis. Default service providers

such as PECO will be required to make their implementation filings a minimum of 12 months prior to the end of the generation rate cap period, which for PECO, expires December 31, 2010. The final Default Service Regulations adopted by the PAPUC will become effective once approved by Pennsylvania’s Independent Regulatory Review Commission (such approval being received on July 19, 2007), and after subsequent review by the Pennsylvania Office of Attorney General, the Pennsylvania Governor’s Budget Office and the standing committees of both houses of the Pennsylvania General Assembly. Once that review and approval process is completed, the regulations would become final once published in the Pennsylvania Bulletin.

Pennsylvania Regulatory Matters (Exelon and PECO). In Pennsylvania and other states where transition periods have ended or rate caps have expired, there is growing pressure from state regulators and politicians to mitigate the potential impact of generation price increases on retail customers. The experiences in other states following the end of a regulatory transition period has led to a heightened state of political concern that significant generation price increases also will occur after the expiration of rate caps in Pennsylvania. While PECO’s regulatory transition period does not end until December 31, 2010, these transition periods have ended for six Pennsylvania electric distribution companies and, in some instances, generations price increases have ensued. Partly in response to the rate increases and as part of his environmental agenda, Pennsylvania Governor Edward Rendell announced an Energy Independence Strategy earlier this year that included a package of proposed legislation. Provisions of that legislation would, among other things, require default suppliers such as PECO to procure electricity for their default-service customers, after the end of their electric restructuring period (post-2010 for PECO), through a least-cost portfolio approach, with preferences for conservation and renewable power. The legislation also would require installation of metering technology to provide time-of-use rates to retail customers, provide for a phase-in of increased generation rates after expiration of rate caps, permit distribution companies to enter into long-term contracts with large industrial customers, and create a fee on electric consumption that the state would direct toward conservation and renewable technologies. On July 18, 2007, Governor Rendell signed into law HB 1203, amending the AEPS Act (amending the force majeure and solar provisions), and HB1530, which amends Title 66 of the Pennsylvania Utility Code, allowing electric distribution companies to negotiate special contracts for larger customers. Other elements of the Governor’s proposed energy package will be considered further at a special legislative session to be held beginning September 17, 2007.

Procurement Auctions (Exelon and Generation). Generation’s power purchase agreement (PPA) with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren procurement auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation is selling more power through bilateral agreements. Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment; therefore, Generation’s credit risk profile has changed based on the credit-worthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the risk of rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to a higher risk of default. If ComEd and Ameren experience adverse financial consequences as a result of any rate freeze or other harmful legislation, there could be material adverse consequences to Exelon and Generation, including, but not limited to: uncertainty in collection of Generation’s receivables from ComEd and Ameren for the electricity previously provided under the supplier forward contracts; uncertainty in the enforcement of Generation’s rights under its supplier forward contracts with ComEd and Ameren and possible negative income tax consequences. A default by ComEd or Ameren on contracts for the purchase of electricity could alter the wholesale power markets and result in Generation selling more power in spot markets.

Market-Based Rates (Exelon and Generation). Generation sells energy pursuant to market-based rate authority that was granted by FERC. On May 19, 2006, FERC issued a Notice of Proposed Rule Making (NOPR) on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities.

The NOPR proposes a set of regulations that would modify the tests that Exelon and other market participants must satisfy to be entitled to market-based rates. On June 21, 2007, FERC issued a Final Rule. Exelon and Generation are currently evaluating impact of the Final Rule.

On December 15, 2006, Generation made a Change in Status (CIS) filing with FERC. The triggering event was the end of the full-requirements PPA between Generation and ComEd and the resulting increase in Generation’s uncommitted capacity. A CIS filing is required when there is a material change in status relied upon by FERC when granting market-based rates authority. Generation’s filing, supported by an updated market-power analysis, demonstrated that Generation continues to be entitled to market-based rates. The time period for interventions expired on January 5, 2007, no party intervened, and on February 9, 2007, FERC accepted Generation’s CIS filing.

Reliability Pricing Model (RPM) (Exelon and Generation). On August 31, 2005, PJM filed its RPM with FERC to replace its current capacity market rules. The RPM proposal provided for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. On November 5, 2005, PJM proposed to delay the effective date of the RPM until June 1, 2007. On April 20, 2006, FERC issued an order generally finding aspects of PJM’s RPM filing to be just and reasonable, but FERC also established further procedures to resolve the remaining issues and encouraged the parties to seek a negotiated resolution. A final settlement was filed with FERC on September 29, 2006 and FERC issued its order approving the settlement, subject to conditions, on December 22, 2006. On June 25, 2007, FERC issued an order denying rehearing on all substantive matters relating to the settlement. FERC’s adoption of the settlement proposal of September 2006 has had a favorable impact for owners of generation facilities, and particularly for such facilities located in constrained zones.

FERC has also denied requests for rehearing of its April 20, 2006 order described above. The time for filing a petition for review of FERC’s April 2006 order expired on February 20, 2007 without any petition for review having been filed. FERC’s December 22, 2006 order approving the settlement, subject to conditions, is subject to requests for rehearing and judicial review. Notwithstanding, PJM has implemented RPM in 2007 as FERC’s orders were not stayed, and therefore remained in effect, pending appellate review, as applicable. The first auction took place in April 2007 and resulted in Generation auctioning capacity at prices ranging from $40.80/MW to $197.67/MW per day for the regions in which Generation has capacity for the period from June 1, 2007 through May 31, 2008. The second auction took place in July 2007 and resulted in Generation auctioning capacity at prices ranging from $111.92/MW to $148.80/MW per day for the regions in which Generation has capacity for the period from June 1, 2008 through May 31, 2009. Subsequent auctions will be conducted in October 2007 and January 2008 to auction capacity for periods through May 2011.

Marginal-Loss Pricing (Exelon and Generation). On June 1, 2007, PJM implemented marginal-loss dispatch and settlement for its competitive wholesale electric market. Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy. Prior to the implementation of marginal-loss dispatch, PJM had used average losses in dispatch and in the calculation of locational marginal prices. Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads. PJM believes that the marginal-loss approach is more efficient because the cost of energy that is lost in transmission lines is reduced compared with the former average loss method. Exelon and Generation continue to evaluate the impact that marginal-loss pricing in PJM will have on the results of operations. As a whole, Exelon and Generation expect to experience an increase in the cost of delivering energy from the generating plant locations to customer load zones due to the implementation of marginal-loss pricing.


6.	Intangible Assets (Exelon and ComEd)

Goodwill (Exelon and ComEd). As of June 30, 2007 and December 31, 2006, Exelon and ComEd had goodwill of approximately $2.6 billion and $2.7 billion, respectively. Under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), goodwill is tested for impairment at least annually or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired, such as a significant negative regulatory outcome. Exelon and ComEd perform their annual goodwill impairment assessment in the fourth quarter of each year.

ComEd and Exelon reviewed the regulatory and economic impacts of the Settlement discussed in Note 5 — Regulatory Issues related to goodwill. This assessment determined that the Settlement was not a trigger (as defined in SFAS No. 142) to review goodwill on an interim basis as it is not “more likely than not” that goodwill is impaired.

The changes in the carrying amount of goodwill for the period from December 31, 2006 to June 30, 2007 were as follows:


Balance as of December 31, 2006	$	2,694
Uncertain tax positions(a)		(53	)

Balance as of June 30, 2007	$	2,641


(a)		For uncertain tax positions of ComEd that existed at October 20, 2000, the date of the merger in which Exelon became the parent corporation of PECO and ComEd (PECO / Unicom merger), the impact of adopting FIN 48 is recorded to goodwill in accordance with Emerging Issues Task Force (EITF) Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination” (EITF 93-7). See Notes 3 and 10 for further information regarding the adoption of FIN 48.

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

Short-Term Borrowings

Exelon, Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and ComEd meets its short-term liquidity requirements primarily through borrowings under its credit facility. Exelon, Generation, ComEd and PECO had the following amounts of commercial paper outstanding at June 30, 2007 and December 31, 2006:


	June 30,		December 31,
Borrower	2007		2006

Exelon Corporate	$	17	$	150
Generation		39		—
ComEd		—		60
PECO		122		95

As of June 30, 2007, Exelon, Generation and PECO have access to unsecured revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion and $600 million, respectively, and ComEd has access to a secured revolving credit facility with aggregate bank commitments of $1 billion. At June 30, 2007 and December 31, 2006, ComEd had $475 million and $0, respectively, of outstanding borrowings under its credit agreement. At June 30, 2007 and December 31, 2006, Exelon, Generation and PECO did not have outstanding borrowings under their credit agreements. See Note 11 of Exelon’s 2006 Annual Report on Form 10-K for further information regarding these credit facilities.

Carrying Amounts and Fair Values of Long-Term Debt

Fair values of long-term debt are determined by a valuation model and are based on a conventional discounted cash flow methodology utilizing assumptions of current market pricing curves.

Exelon

The carrying amounts and fair values of Exelon’s long-term debt as of June 30, 2007 and December 31, 2006 were as follows:


	June 30, 2007				December 31, 2006
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

Long-term debt (including amounts due within one year)	$	9,412	$	9,178	$	9,144	$	9,122
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust (PETT) (including amounts due within one year)		2,494		2,557		3,051		3,149
Long-term debt to other financing trusts		545		474		545		517

Generation

The carrying amounts and fair values of Generation’s long-term debt as of June 30, 2007 and December 31, 2006 were as follows:


	June 30, 2007				December 31, 2006
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

Long-term debt (including amounts due within one year)	$	1,790	$	1,798	$	1,790	$	1,821

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of June 30, 2007 and December 31, 2006 were as follows:


	June 30, 2007				December 31, 2006
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

Long-term debt (including amounts due within one year)	$	3,722	$	3,644	$	3,579	$	3,592
Long-term debt to ComEd Transitional Funding Trust (including amounts due within one year)		443		445		648		652
Long-term debt to other financing trusts		361		306		361		338

ComEd intends to refinance maturing long-term debt and to repay a portion of its credit facility borrowings with long-term debt. As of June 30, 2007, ComEd has the capacity to issue up to approximately $460 million of additional first mortgage bonds subject to certain restrictions.

PECO

The carrying amounts and fair values of PECO’s long-term debt as of June 30, 2007 and December 31, 2006 were as follows:


	June 30, 2007				December 31, 2006
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

Long-term debt (including amounts due within one year)	$	1,650	$	1,611	$	1,469	$	1,464
Long-term debt to PETT (including amounts due within one year)		2,050		2,112		2,404		2,496
Long-term debt to other financing trusts		184		168		184		179

Issuance of Long-Term Debt

During the six months ended June 30, 2007, the following long-term debt was issued:

Interest

Company

Type

Rate

Maturity

Amount(a)

ComEd

First Mortgage Bonds

5.90

March 15, 2036

300

PECO

First and Refunding Mortgage Bonds

5.70

March 15, 2037

175

Other


(a)		Excludes unamortized bond discounts.

Retirement of Long-Term Debt

During the six months ended June 30, 2007, the following long-term debt was retired:


		Interest
Company	Type	Rate			Maturity	Amount

Exelon	Notes payable for investments in synthetic fuel-producing facilities		6.00-8.00	%	Various	$	52
ComEd	Notes payable		7.625	%	January 15, 2007		145
ComEd	ComEd Transitional Funding Trust		5.63	%	June 25, 2007		138	(a)(b)
ComEd	ComEd Transitional Funding Trust		5.74	%	December 25, 2008		67
ComEd	Sinking fund debenture		4.75	%	December 1, 2011		1
PECO	PETT		6.13	%	September 1, 2008		354


(a)		Amount includes $17 million previously reflected in prepaid interest. This amount did not have an impact on ComEd’s Consolidated Statement of Operations or ComEd’s Consolidated Statement of Cash Flows.

(b)		ComEd applied $8 million of previously prepaid balances against the long-term debt to ComEd Transitional Funding Trust.


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

Interest-Rate Swaps (Exelon, Generation, ComEd and PECO)

The fair values of Exelon’s, Generation’s, ComEd’s and PECO’s interest-rate swaps are determined using quoted exchange prices, external dealer prices and available market pricing curves.

Fair-Value Hedges. The Registrants may utilize fixed-to-floating interest-rate swaps from time to time as a means to achieve their targeted level of variable-rate debt as a percent of total debt. At June 30, 2007 and December 31, 2006, Exelon had $100 million and $50 million, respectively, of notional amounts of fair-value hedges outstanding. Fixed-to-floating interest-rate swaps are designated as fair-value hedges, as defined in SFAS No. 133, and, as such, changes in the fair value of the swaps are recorded in earnings; however, as long as the hedge remains effective and the underlying liability remains outstanding, changes in the fair value of the swaps are offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. During the three and six months ended June 30, 2007 and 2006, no amounts relating to fair-value hedges were recorded in earnings as a result of ineffectiveness.

Cash-Flow Hedges. The Registrants utilize interest rate derivatives from time to time to lock in interest-rate levels in anticipation of future financings. Forward-starting interest-rate swaps are designated as cash-flow hedges, as defined in SFAS No. 133, and, as such, changes in the fair value of the swaps are recorded in other comprehensive income (OCI). Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. At June 30, 2007 and 2006, the Registrants did not have any notional amounts of interest-rate related cash-flow hedges outstanding. During the three and six months ended June 30, 2007 and 2006, the Registrants did not reclassify any amounts from accumulated OCI into earnings as a result of ineffectiveness.

Energy-Related Derivatives (Exelon, Generation, ComEd and PECO)

Generation utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates and others. Exelon and Generation also utilize energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into certain energy-related derivatives for trading or speculative purposes.

The Registrants’ energy contracts are accounted for under SFAS No. 133. Economic hedges may qualify for the normal purchases and normal sales exception to SFAS No. 133 and are accounted for under the accrual method of accounting. Those that do not meet the normal purchases and normal sales exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs or are designated as fair-value hedges, in which case those changes are recognized in current earnings offset by changes in the fair value of the hedged item in current earnings. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 (or are not designated as such) and proprietary trading contracts, in the case of Generation, are recognized in current earnings. Generation also has contracted for access to additional generation and sales to load-serving entities that are accounted for under the accrual method of accounting discussed in Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K.

ComEd has derivatives to manage its market price exposures to certain wholesale contracts that extend through 2008. The contracts that ComEd has entered into as part of the initial ComEd auction (See Note 5 — Regulatory

Issues) are deemed to be derivatives that qualify for the normal purchases and normal sales exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes.

Some of PECO’s gas supply agreements are derivatives that qualify for the normal purchases and normal sales exception to SFAS No. 133. PECO does not enter into derivatives for speculative or trading purposes.

At June 30, 2007, Exelon, Generation and ComEd had net assets (liabilities) of $25 million, $33 million and $(5) million, respectively, on their Consolidated Balance Sheets for the fair value of energy derivatives. The following table provides a summary of the fair value balances recorded by Exelon, Generation and ComEd as of June 30, 2007:


	June 30, 2007
																								Exelon
	Generation												ComEd											Energy-
	Cash-Flow			Other			Proprietary						Cash-Flow		Other									Related
Derivatives	Hedges			Derivatives			Trading			Subtotal			Hedge		Derivatives			Subtotal			Other(a)			Derivatives(b)

Current assets	$	231		$	415		$	103		$	749		$	—	$	—		$	—		$	16		$	765
Noncurrent assets		75			105			30			210			—		—			—			—			210

Total mark-to-market energy contract assets	$	306		$	520		$	133		$	959		$	—	$	—		$	—		$	16		$	975

Current liabilities	$	(106	)	$	(444	)	$	(78	)	$	(628	)	$	—	$	(5	)	$	(5	)	$	(16	)	$	(649	)
Noncurrent liabilities		(147	)		(135	)		(16	)		(298	)		—		—			—			(3	)		(301	)

Total mark-to-market energy contract liabilities	$	(253	)	$	(579	)	$	(94	)	$	(926	)	$	—	$	(5	)	$	(5	)	$	(19	)	$	(950	)

Total mark-to-market energy contract net assets (liabilities)	$	53		$	(59	)	$	39		$	33		$	—	$	(5	)	$	(5	)	$	(3	)	$	25


(a)		Other includes corporate operations, shared service entities, including Exelon Business Services Company (BSC), Enterprises and investments in synthetic fuel-producing facilities.

(b)		Excludes Exelon’s interest-rate swaps.

At December 31, 2006, Exelon, Generation and ComEd had net assets (liabilities) of $496 million, $499 million and $(11) million, respectively, on their Consolidated Balance Sheets for the fair value of energy derivatives. The following table provides a summary of the fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2006:


	December 31, 2006
																									Exelon
	Generation												ComEd												Energy-
	Cash-Flow			Other			Proprietary						Cash-Flow			Other									Related
Derivatives	Hedges			Derivatives			Trading			Subtotal			Hedge			Derivatives			Subtotal			Other(a)			Derivatives(b)

Current assets	$	460		$	751		$	197		$	1,408		$	—		$	—		$	—		$	10		$	1,418
Noncurrent assets		104			52			15			171			—			—			—			—			171

Total mark-to-market energy contract assets	$	564		$	803		$	212		$	1,579		$	—		$	—		$	—		$	10		$	1,589

Current liabilities	$	(119	)	$	(697	)	$	(187	)	$	(1,003	)	$	(6	)	$	(5	)	$	(11	)	$	(1	)	$	(1,015	)
Noncurrent liabilities		(30	)		(33	)		(14	)		(77	)		—			—			—			(1	)		(78	)

Total mark-to-market energy contract liabilities	$	(149	)	$	(730	)	$	(201	)	$	(1,080	)	$	(6	)	$	(5	)	$	(11	)	$	(2	)	$	(1,093	)

Total mark-to-market energy contract net assets (liabilities)	$	415		$	73		$	11		$	499		$	(6	)	$	(5	)	$	(11	)	$	8		$	496


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(b)		Excludes Exelon’s interest-rate swaps.

Normal Operations and Hedging Activities (Generation). Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s contracted auction requirement and PECO’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures.

Cash-Flow Hedges (Generation and ComEd). The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on Exelon’s, Generation’s and ComEd’s Consolidated Balance Sheets as of June 30, 2007. The data in the table is indicative of the magnitude of SFAS No. 133 hedges Generation and ComEd have in place; however, since under SFAS No. 133 not all derivatives are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s and ComEd’s derivatives. The tables also include the activity of accumulated OCI related to cash-flow hedges for the three and six months ended June 30, 2007 and 2006, providing information about the changes in the fair value of hedges and the reclassification from accumulated OCI into earnings.


	Total Cash-Flow Hedge
	OCI Activity, Net of
	Income Tax
Three Months Ended June 30, 2007	Generation			ComEd			Exelon

Accumulated OCI derivative loss at March 31, 2007	$	(174	)	$	(1	)	$	(175	)
Changes in fair value		211			—			211
Reclassifications from accumulated OCI to net income		(4	)		1			(3	)

Accumulated OCI derivative gain at June 30, 2007	$	33		$	—		$	33


	Total Cash-Flow Hedge
	OCI Activity, Net of
	Income Tax
Six Months Ended June 30, 2007	Generation			ComEd			Exelon

Accumulated OCI derivative gain (loss) at December 31, 2006	$	250		$	(4	)	$	246
Changes in fair value		(200	)		—			(200	)
Reclassifications from accumulated OCI to net income		(17	)		4			(13	)

Accumulated OCI derivative gain at June 30, 2007	$	33		$	—		$	33


	Total Cash-Flow Hedge
	OCI Activity, Net of
	Income Tax
Three Months Ended June 30, 2006	Exelon and Generation

Accumulated OCI derivative loss at March 31, 2006	$	(223	)
Changes in fair value		117
Reclassifications from accumulated OCI to net income		22

Accumulated OCI derivative loss at June 30, 2006	$	(84	)


	Total Cash-Flow Hedge
	OCI Activity, Net of
	Income Tax
Six Months Ended June 30, 2006	Exelon and Generation

Accumulated OCI derivative loss at December 31, 2005	$	(314	)
Changes in fair value		163
Reclassifications from accumulated OCI to net income		67

Accumulated OCI derivative loss at June 30, 2006	$	(84	)

At June 30, 2007, Generation had net unrealized pre-tax gains on cash-flow hedges of $55 million in accumulated OCI. Based on market prices at June 30, 2007, approximately $125 million of these deferred net pre-tax unrealized gains on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months by Generation. However, the actual amount reclassified to earnings could vary due to future changes in market prices. Amounts recorded in accumulated OCI related to changes in energy commodity cash-flow hedges are reclassified to earnings when the forecasted purchase or sale of the energy commodity occurs. Generation expects that the majority of its cash-flow hedges will settle within the next two years.

Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was an $8 million and $29 million pre-tax gain for the three and six months ended June 30, 2007, respectively, and a $36 million and $112 million pre-tax loss for the three and six months ended June 30, 2006, respectively. During the three and six months ended June 30, 2007 and 2006, amounts reclassified from accumulated OCI into earnings as a result of ineffectiveness were not material to the financial statements.

Other Derivatives (Exelon, Generation and ComEd). Exelon, Generation and ComEd enter into certain contracts that are derivatives, but do not qualify for hedge accounting under SFAS No. 133 or are not designated as cash-flow hedges. These contracts are also entered into to economically hedge and limit the market price risk associated with energy commodity prices. Changes in the fair value of these derivative contracts are recognized in current earnings. For the three and six months ended June 30, 2007 and 2006, Exelon, Generation and ComEd

recognized the following net unrealized mark-to-market gains (losses), realized mark-to-market gains (losses) and total mark-to-market gains (losses) (before income taxes) relating to economic hedge mark-to-market activity of certain purchase power and sale contracts pursuant to SFAS No. 133. Generation’s, ComEd’s and Exelon’s other economic hedge mark-to-market activity on purchase power and sale contracts are reported in fuel and purchased power, revenue and operating and maintenance expense, respectively.


	Three Months Ended June 30, 2007
	Generation			ComEd(a)			Other(b)			Exelon

Unrealized mark-to-market losses	$	(5	)	$	(3	)	$	(10	)	$	(18	)
Realized mark-to-market gains (losses)		(12	)		1			—			(11	)

Total net mark-to-market losses	$	(17	)	$	(2	)	$	(10	)	$	(29	)


(a)		See “Energy-Related Derivatives” above.

(b)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.


	Six Months Ended June 30, 2007
	Generation			ComEd(a)			Other(b)			Exelon

Unrealized mark-to-market losses	$	(81	)	$	(2	)	$	(11	)	$	(94	)
Realized mark-to-market gains (losses)		(54	)		2			—			(52	)

Total net mark-to-market losses	$	(135	)	$	—		$	(11	)	$	(146	)


(a)		See “Energy-Related Derivatives” above.

(b)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.


	Three Months Ended June 30, 2006
	Generation		ComEd(a)		Other(b)		Exelon

Unrealized mark-to-market gains	$	30	$	2	$	28	$	60
Realized mark-to-market gains		28		1		—		29

Total net mark-to-market gains	$	58	$	3	$	28	$	89


(a)		See “Energy-Related Derivatives” above.

(b)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.


	Six Months Ended June 30, 2006
	Generation			ComEd(a)			Other(b)		Exelon

Unrealized mark-to-market gains (losses)	$	(26	)	$	(9	)	$	41	$	6
Realized mark-to-market gains		63			1			—		64

Total net mark-to-market gains (losses)	$	37		$	(8	)	$	41	$	70


(a)		See “Energy-Related Derivatives” above.

(b)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

Proprietary Trading Activities (Generation). Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s Risk Oversight Committee. These contracts are recognized on the Consolidated Balance Sheets at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. The proprietary trading activities, which included volumes of 4,775 GWhs and 9,876 GWhs for the three and six months ended June 30, 2007, respectively, and 7,769 GWhs and 14,754 GWhs for the three and six months ended June 30, 2006, respectively, are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s revenue from energy marketing activities. For the three and six months ended June 30, 2007 and 2006, Exelon and Generation recognized the following net unrealized mark-to-market gains, realized mark-to-market losses and total net mark-to-market gains (before income taxes) relating to mark-to-market activity on derivative instruments entered into for trading purposes. Gains and losses associated with proprietary trading are reported as revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006

Unrealized mark-to-market gains	$	32		$	2		$	32		$	4
Realized mark-to-market losses		(2	)		(2	)		(4	)		(4	)

Total net mark-to-market gains	$	30		$	—		$	28		$	—

Credit Risk Associated with Derivative Instruments (Exelon and Generation)

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 derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation attempts to enter 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 allows for cross product netting. In addition to payment netting language in the enabling agreement, the credit department establishes credit limits and letter of credit requirements for each counterparty, which are defined in the derivatives 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 credit limit and letter of credit 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.

Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings have been one-sided from Generation only. That is, when market prices have fallen below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren have not been required to post collateral; however, when market prices have risen above contracted price levels with ComEd or Ameren, Generation has been required to post collateral.

The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of the Registrant’s exposure. The amounts exchanged are calculated on the basis of the notional or

contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates. Exelon’s and Generation’s credit exposure, net of collateral, as of June 30, 2007 and December 31, 2006 were $870 million and $791 million, respectively.

As of June 30, 2007, Generation had $257 million of collateral deposit payments being held by counterparties and Generation was holding $6 million of collateral deposits received from counterparties.


9.	Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and Exelon Corporate employees, except for those employees of Generation’s wholly owned subsidiary, AmerGen, who participate in the separate AmerGen-sponsored defined benefit pension plan and postretirement benefit plan.

In 2006, President Bush signed into law the Pension Protection Act of 2006 (the Act), which will affect the manner in which many companies, including Exelon and Generation, administer their pension plans. This legislation will be effective as of January 1, 2008 and may require companies to, among other things, increase the amount by which they fund their pension plans, pay higher premiums to the Pension Benefit Guaranty Corporation if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants. The Registrants are currently unable to determine whether the Act or possible further regulation will have a material impact on their liquidity and capital resources. The Registrants are currently assessing the potential impact of the Act.

Defined Benefit Pension and Other Postretirement Benefits — Consolidated Plans (Exelon, Generation, ComEd and PECO)

In the second quarter of 2007, Exelon received the final valuations of its pension and other postretirement benefit obligations to reflect actual census data as of December 31, 2006. This valuation resulted in an increase to the pension obligations of $17 million and a decrease to other postretirement obligations of $75 million. Additionally, OCI increased by approximately $19 million. The impact to the Consolidated Statement of Operations and Comprehensive Income is not material.

The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, 2007 and 2006. The 2007 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.75%. The 2007 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.87%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

Exelon calculates the expected return on pension and other postretirement benefit plan assets by multiplying the expected long-term rate of return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. SFAS No. 87, “Employer’s Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. Exelon uses a calculated value when determining the MRV of the pension plan assets that adjusts for 20% of the difference between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which Exelon applies that expected return. Exelon uses fair value when determining the MRV of the other postretirement benefit plan assets.


							Other
	Pension						Postretirement
	Benefits						Benefits
	Three Months						Three Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006

Service cost	$	40		$	38		$	28		$	25
Interest cost		151			139			47			44
Expected return on assets		(204	)		(204	)		(30	)		(27	)
Amortization of:
Transition obligation		—			—			3			3
Prior service cost (benefit)		4			4			(14	)		(23	)
Actuarial loss		37			34			15			21

Net periodic benefit cost	$	28		$	11		$	49		$	43


							Other
	Pension						Postretirement
	Benefits						Benefits
	Six Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006

Service cost	$	81		$	79		$	53		$	50
Interest cost		302			281			96			91
Expected return on assets		(408	)		(408	)		(58	)		(53	)
Amortization of:
Transition obligation		—			—			5			5
Prior service cost (benefit)		8			8			(28	)		(46	)
Actuarial loss		74			74			32			44

Net periodic benefit cost	$	57		$	34		$	100		$	91

The following approximate amounts were included in capital and operating and maintenance expense during the three and six months ended June 30, 2007 and 2006, respectively, for Generation’s, ComEd’s, PECO’s and Exelon Corporate’s allocated portion of the Exelon-sponsored and AmerGen-sponsored pension and postretirement benefit plans:


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Pension and Postretirement Benefit Costs	2007		2006		2007		2006

Generation	$	35	$	26	$	71	$	57
ComEd		27		19		51		38
PECO		6		5		16		15
Exelon Corporate(a)		9		4		19		15


(a)		Represents amounts billed to Exelon’s subsidiaries through intercompany allocations.

Pension and Other Postretirement Benefits — AmerGen Plans (Generation)

The following tables present the components of net periodic benefit costs for the three and six months ended June 30, 2007 and 2006 for the AmerGen-sponsored plans. The 2007 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.75%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets. AmerGen uses fair value for purposes of determining the MRV of the pension and other postretirement benefit plan assets.


							Other
	Pension						Postretirement
	Benefits						Benefits
	Three Months						Three Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006

Service cost	$	3		$	3		$	2		$	2
Interest cost		2			1			2			2
Expected return on assets		(2	)		(1	)		—			—
Amortization of prior service cost		—			—			(1	)		(1	)

Net periodic benefit cost	$	3		$	3		$	3		$	3


							Other
	Pension						Postretirement
	Benefits						Benefits
	Six Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006

Service cost	$	6		$	6		$	4		$	4
Interest cost		4			3			3			3
Expected return on assets		(4	)		(3	)		—			—
Amortization of prior service cost		—			—			(1	)		(1	)

Net periodic benefit cost	$	6		$	6		$	6		$	6

401(k) Savings Plan (Exelon, Generation, ComEd and PECO)

Exelon, Generation, ComEd and PECO participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon, Generation, ComEd and PECO match a percentage of the employee contribution up to certain limits. The following table presents, by Registrant, the matching contribution to the savings plans during the three and six months ended June 30, 2007 and 2006:


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Savings Plan Matching Contributions	2007		2006		2007		2006

Exelon	$	16	$	15	$	32	$	30
Generation		7		8		15		16
ComEd		5		4		9		8
PECO		2		1		3		3


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

The Registrants’ effective income tax rate from continuing operations for the three and six months ended June 30, 2007 and 2006 varied from the U.S. Federal statutory rate principally due to the following:


	Three Months Ended June 30, 2007
	Exelon			Generation			ComEd			PECO

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.9			4.3			4.7			(0.2	)
Qualified nuclear decommissioning trust fund income		0.8			0.9			—			—
Plant basis differences		—			—			—			0.1
Synthetic fuel-producing facilities credit(a)		(6.5	)		—			—			—
Domestic production activities deduction		(1.5	)		(1.9	)		—			—
Tax exempt income		(0.4	)		(0.4	)		—			—
Amortization of investment tax credit		(0.3	)		(0.2	)		(1.6	)		(0.4	)
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(1.6	)		(0.5	)
Allowance for funds used during construction (AFUDC), equity		—			—			(0.5	)		—
Lobbying activities		—			—			2.2			—
Investment tax credit charge		0.3			—			—			2.3
Other		(0.1	)		0.1			0.1			0.1

Effective income tax rate		30.9	%		37.6	%		38.3	%		36.4	%


(a)		See Notes 2 and 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information regarding investments in synthetic fuel-producing facilities.


	Six Months Ended June 30, 2007
	Exelon			Generation			ComEd			PECO

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		4.7			4.8			4.7			(0.6	)
Qualified nuclear decommissioning trust fund income		0.5			0.7			—			—
Plant basis differences		—			—			—			0.3
Synthetic fuel-producing facilities credit(a)		(5.6	)		—			—			—
Domestic production activities deduction		(1.5	)		(1.7	)		—			—
Tax exempt income		(0.3	)		(0.4	)		—			—
Amortization of investment tax credit		(0.3	)		(0.1	)		(1.6	)		(0.3	)
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(1.6	)		(0.3	)
AFUDC, equity		—			—			(0.4	)		—
Lobbying activities		0.1			—			2.0			—
Investment tax credit charge		0.2			—			—			1.0
Other		(0.6	)		(0.5	)		0.8			—

Effective income tax rate		31.9	%		37.6	%		38.9	%		35.1	%


(a)		See Notes 2 and 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information regarding investments in synthetic fuel-producing facilities.


	Three Months Ended June 30, 2006
	Exelon			Generation			ComEd			PECO

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.7			4.4			4.9			(2.1	)
Qualified nuclear decommissioning trust fund income		0.3			0.4			—			—
Amortization of regulatory asset		—			—			0.7			—
Plant basis differences		0.1			—			—			0.8
Domestic production activities deduction		(0.5	)		(0.6	)		—			—
Tax exempt income		(0.3	)		(0.4	)		—			—
Amortization of investment tax credit		(0.3	)		(0.1	)		(0.3	)		(0.4	)
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(0.3	)		(0.3	)
Other		(1.5	)		(1.3	)		0.4			(0.4	)

Effective income tax rate		36.2	%		37.2	%		40.4	%		32.6	%


	Six Months Ended June 30, 2006
	Exelon			Generation			ComEd			PECO

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.6			4.4			4.8			(1.3	)
Qualified nuclear decommissioning trust fund income		0.4			0.5			—			—
Amortization of regulatory asset		—			—			0.7			—
Plant basis differences		0.1			—			—			0.4
Synthetic fuel-producing facilities credit(a)		(1.6	)		—			—			—
Domestic production activities deduction		(0.6	)		(0.8	)		—			—
Tax exempt income		(0.4	)		(0.5	)		—			—
Amortization of investment tax credit		(0.4	)		(0.2	)		(0.5	)		(0.4	)
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(0.4	)		(0.3	)
Lobbying activities		—			—			0.2			—
Other		(0.7	)		(1.0	)		0.7			(0.1	)

Effective income tax rate		35.1	%		37.2	%		40.5	%		33.3	%


(a)		See Notes 2 and 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information regarding investments in synthetic fuel-producing facilities.

Accounting for Uncertainty in Income Taxes (Exelon, Generation, ComEd and PECO)

The Registrants adopted the provisions of FIN 48 on January 1, 2007. The following table shows the effect of adopting FIN 48 on the Registrants’ Consolidated Balance Sheets as of January 1, 2007.


Increase (decrease)	Exelon			Generation			ComEd			PECO

Accounts receivable, net — Other	$	83		$	—		$	72		$	12
Goodwill		(53	)		—			(53	)		—
Other deferred debits and other assets		381			22			137			208
Accrued expenses		(197	)		5			(186	)		—
Deferred income taxes and unamortized investment tax credits		(83	)		30			(299	)		186
Other deferred credits and other liabilities		705			31			642			11
Retained earnings		(14	)		(44	)		(1	)		23

As a result of the implementation of FIN 48, Exelon, Generation, ComEd, and PECO have identified unrecognized tax benefits of $1.5 billion, $311 million, $797 million and $318 million, respectively, as of January 1, 2007.

Generation has identified $51 million of its unrecognized tax expense at January 1, 2007 that, if recognized, would increase the effective tax rate. ComEd has identified $21 million of its unrecognized tax benefit at January 1, 2007 that, if recognized, would decrease the effective tax rate.

Generation and PECO have reflected in their Consolidated Balance Sheets as of January 1, 2007 a net interest receivable of $1 million and $21 million, respectively, related to their uncertain income tax positions. Exelon and

ComEd have reflected in their Consolidated Balance Sheets as of January 1, 2007 a net interest liability of $130 million and $167 million, respectively, related to their uncertain income tax positions. The Registrants have not accrued any penalties with respect to unrecognized income tax benefits. The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or interest income in operating and maintenance expense on their Consolidated Statements of Operations. Exelon has reflected in its Consolidated Statement of Operations net interest expense of $6 million and $10 million related to its uncertain income tax positions for the three and six months ended June 30, 2007, respectively. ComEd has reflected in its Consolidated Statement of Operations net interest expense of $8 million and $17 million related to its uncertain income tax positions for the three and six months ended June 30, 2007, respectively. PECO has reflected in its Consolidated Income Statement net interest income of $2 million and $5 million related to its uncertain income tax positions for the three and six months ended June 30, 2007, respectively.

Exelon and its subsidiaries file a consolidated U.S. Federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Illinois being the most significant. Exelon and its subsidiaries also file separate company income tax returns in several states with Pennsylvania being the most significant. Exelon and its subsidiaries have completed examinations by the Internal Revenue Service (IRS) for taxable years prior to 1999; however several tax issues remain unresolved for tax years prior to 1999 and have been protested to IRS Appeals, the next administrative level within the IRS. In the second quarter of 2004, the IRS commenced an audit of Exelon and its subsidiaries for taxable years 1999 through 2001 and is expected to complete the audit by the end of 2007. Exelon and its subsidiaries have also completed examinations by the state of Illinois for taxable years prior to 1999 and by the Commonwealth of Pennsylvania on the separate company income tax returns for taxable years ending from 2000 to 2003. However, to the extent adjustments are made to these prior years as either part of a settlement at IRS Appeals or IRS Examination, the state taxable income may also be adjusted.

It is reasonably possible that the amount of unrecognized tax benefits will significantly increase or decrease in the next twelve months as a result of settling several uncertain tax positions. ComEd is in the process of negotiating with IRS Appeals a settlement related to research and development refund claims filed by ComEd for taxable years 1989 through 1998. At this point, an estimate of a change, if any, to the unrecognized tax benefit amount cannot be made. A majority of the refund claim relates to ComEd’s formerly owned generation property. Pursuant to the asset transfer agreement between ComEd and Generation, any current tax benefit related to this unrecognized tax benefit as well as a portion of the related interest income would be recorded to ComEd’s goodwill as it relates to taxable periods prior to the PECO / Unicom merger as required under EITF 93-7. Generation would record the offsetting future deferred tax effects, which would impact future period earnings. ComEd and PECO also have several other issues at IRS Appeals for taxable years 1996 through 1998 that, if settled, would not significantly increase or decrease the total amount of unrecognized tax benefits.

Exelon filed refund claims for investment tax credits with respect to its utility property with the Illinois Department of Revenue. Although those claims were denied by the Illinois Department of Revenue, Exelon has filed a suit for a refund. The case is now before the Illinois Appellate Court and a decision is likely to occur within the next twelve months. It is reasonably possible that the amount of unrecognized tax benefit will decrease by as much as $71 million, $16 million and $55 million for Exelon, Generation and ComEd, respectively.

As part of the Federal examination of taxable years 1999 through 2001, the IRS has issued proposed adjustments related to ComEd’s deferral of gain on the 1999 sale of its fossil plants. See “1999 Sale of Fossil Generating Assets” below for details. ComEd’s management is in the process of evaluating its options with respect to the proposed tax deficiency. Those options include either protesting the disallowance to the IRS Appeals Division or possible litigation. If ComEd’s management decides to litigate the matter, ComEd may be required to pay the tax and related interest due on the deficiency and file for refund. Upon payment of the tax and related interest, ComEd

would reassess its tax position with respect to the gain deferral of the fossil plant sale. As a result of this reassessment, the unrecognized tax benefits may decrease by as much as $428 million.

The IRS proposed an adjustment requiring the capitalization of certain merger costs previously deducted, associated with the PECO / Unicom merger. In the second quarter of 2007, management agreed to accept the IRS’ adjustment to capitalize the merger costs. Exelon and PECO reduced the amount of unrecognized tax benefits by approximately $16 million and $10 million, respectively.

Generation and ComEd filed refund claims related to taxable years 1999 through 2004 for research and development expenditures. The IRS is in the early stages of the audit of those claims. At this point, an estimate of a change, if any, to the unrecognized tax benefit amount cannot be made.

In 2001, ComEd and PECO filed a request with the IRS to change their tax method of accounting for certain capitalized overhead costs. The requested tax method of accounting, the Simplified Service Cost Method (SSCM), is expressly permitted under IRS regulations. The effect of the tax method change results in the immediate expensing of certain overhead costs that were previously capitalized to self-constructed property. During the first quarter of 2007, the IRS granted the tax method change. In April 2007, ComEd and PECO signed consent agreements, thus making the tax method change effective as of that date. The consent agreement has terms and conditions that subject the change to certain published guidance as well as future guidelines and directives to be issued by the IRS. As a result of the uncertainty of forthcoming IRS settlement guidelines, ComEd and PECO are currently unable to estimate the tax benefit associated with the SSCM. ComEd and PECO have entered into an agreement with a tax consultant related to the filing of this tax method change request. The fee for this agreement is contingent upon receiving consent from the IRS and is based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash impacts to ComEd and PECO related to this agreement will either be positive or neutral depending upon the outcome of the refund claim with the IRS. A portion of the tax refund, if any, will likely relate to ComEd and PECO’s formerly owned generation property and thus the current tax benefits will be recorded by ComEd and PECO with partially offsetting deferred tax effects at Generation. These potential tax benefits and associated fees would be recorded in accordance with FIN 48 and SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), respectively, and could be material to the financial position, results of operations and cash flows of Generation, ComEd and PECO.

Certain of ComEd and PECO’s tax positions evaluated under FIN 48 are dependent on ComEd and PECO having sufficient tax basis in their fixed assets. Should ComEd and PECO obtain any future benefit associated with the SSCM accounting method change, it will require a reduction to the tax basis of assets. As a result, the SSCM could have an effect on the unrecognized tax benefits associated with other tax positions that are dependent on tax basis.

1999 Sale of Fossil Generating Assets (Exelon, Generation and ComEd)

Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of June 30, 2007 and December 31, 2006, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to ComEd and the remainder to Generation. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of the sales proceeds, as having been received in connection with an involuntary conversion is proper pursuant to applicable law. In November 2006, ComEd received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its position that proceeds from the fossil plant sales resulted from an “involuntary conversion.”

Exelon’s and ComEd’s ability to continue to defer the remainder of the tax liability on the fossil plant sale may depend in part on whether its tax characterization of a sale leaseback transaction Exelon entered into in connection with the fossil plant sale is proper pursuant to applicable law. In February 2007, Exelon received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its sale-leaseback transaction. The IRS has indicated its position that the Exelon sale leaseback transaction is substantially similar to a leasing transaction, a sale-in, lease-out (SILO), the IRS is treating as a “listed transaction” pursuant to guidance it issued in 2005. A listed transaction is one, which the IRS considers to be a potentially abusive tax shelter. Exelon disagrees with the IRS’s characterization of its sale-leaseback as a SILO and believes its position is justified and will continue to aggressively defend that position upon audit and any subsequent appeals or litigation.

In final form, both the disallowance for the involuntary conversion and the like kind exchange transactions will be in the IRS’ audit report expected to be issued in the third quarter of 2007. Upon receipt of the final IRS report, Exelon will have the opportunity to either appeal the disallowance to IRS Appeals, the next administrative level of the IRS, or litigate the matter. If Exelon’s and ComEd’s management decide to litigate the matter, it may be required to pay the tax and related interest due on the deficiency and file for refund.

A successful IRS challenge to ComEd’s positions would accelerate future income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of June 30, 2007, Exelon’s and ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $983 million. If the deferral were successfully challenged by the IRS, it could negatively impact Exelon’s and ComEd’s results of operations by as much as $153 million (after tax) related to interest expense. Exelon’s and ComEd’s management believe an appropriate reserve for interest has been recorded in accordance with FIN 48; however, the ultimate outcome of such matters could result in unfavorable or favorable impacts to the results of operations, and such adjustments could be material. Final resolution of this matter is not anticipated for several years.

Investments in Synthetic Fuel-Producing Facilities (Exelon)

Exelon, through three separate wholly owned subsidiaries, owns interests in two limited liability companies and one limited partnership (collectively, the Sellers) that own synthetic fuel-producing facilities. Section 45K (formerly Section 29) of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45K contains a provision under which the tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. Exelon is required to pay for tax credits based on the production of the facilities regardless of whether or not a phase-out of the tax credits is anticipated. However, Exelon has the legal right to recover a portion of the payments made to the Sellers related to phased-out tax credits.

In April 2007, the IRS published the 2006 oil Reference Price which resulted in a 33% phase-out of tax credits for calendar year 2006 which reduced Exelon’s earned after-tax credits of $164 million to $110 million for the year ended December 31, 2006. At December 31, 2006, Exelon had estimated the 2006 phase-out to be 38% and had receivables on its Consolidated Balance Sheet from the Sellers totaling $63 million associated with the portion of the payments previously made to the Sellers related to tax credits that were anticipated to be phased out for 2006. The difference between the actual 2006 phase-out and the 2006 phase-out previously estimated resulted in a $9 million increase in 2006 tax credits and a corresponding $6 million decrease, net of the related tax benefit, in the receivables due from the Sellers, which has been reflected in Exelon’s operating results for the three and six months ended June 30, 2007.

The following table (in dollars) provides the estimated phase-out range for 2007 based on the per barrel price of oil as of June 30, 2007. The table also contains the estimated 2007 annual average New York Mercantile Exchange, Inc. index (NYMEX) price per barrel at June 30, 2007 based on year-to-date and futures prices.


	Estimated
	2007

Beginning of Phase-Out Range(a)	$	62
End of Phase-Out Range(a)		78
2007 Annual Average NYMEX		66


(a)		The estimated 2007 phase-out range as of June 30, 2007 is based upon the actual 2006 phase-out range. The actual 2006 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2007. The actual 2006 phase-out range was increased by 2% (Exelon’s estimate of inflation) to arrive at the estimated 2007 phase-out range.

At June 30, 2007, Exelon had receivables on its Consolidated Balance Sheet from the Sellers totaling $34 million associated with the portion of the payments previously made to the Sellers related to tax credits that are anticipated to be phased out in 2007. As of June 30, 2007, Exelon has estimated the 2007 phase-out to be 25%, which has reduced Exelon’s earned after-tax credits of $139 million to $105 million for the six months ended June 30, 2007. These credits may be further phased out during the remainder of 2007 depending on the price of oil; however, as these tax credits are phased out, Exelon anticipates recording income through the establishment of additional receivables from the Sellers or from derivatives entered into in 2005 (as more fully described below) depending on the magnitude of the credits phased-out.

In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of the exposure to a phase-out of the tax credits. One of the Sellers has security interests in these derivatives. Including the related mark-to-market gains and losses on these derivatives, interests in synthetic fuel-producing facilities increased Exelon’s net income by $27 million and reduced Exelon’s net income by $55 million during the three months ended June 30, 2007 and 2006, respectively. Additionally, interests in synthetic fuel-producing facilities increased Exelon’s net income by $52 million and reduced Exelon’s net income by $43 million during the six months ended June 30, 2007 and 2006, respectively. Exelon anticipates that it will continue to record income or losses related to the mark-to-market gains or losses on its derivative instruments and changes to the tax credits earned by Exelon during the period of production as a result of volatility in oil prices.

Net income from interests in synthetic fuel-producing facilities is reflected in the Consolidated Statements of Operations and Comprehensive Income within income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and investments and other, net.

There are provisions in the agreements between the parties, such as low production volume, unanimous consents between the parties and defaults by the parties, which would allow or cause an early termination of the partnerships. If none of the parties to the agreements takes action to terminate the partnerships early, the partnerships will terminate in 2008.

The non-recourse notes payable principal balance was $56 million and $108 million at June 30, 2007 and December 31, 2006, respectively. The non-recourse notes payable can be relieved either through eventual payments or possibly through extinguishment, which may occur subsequent to termination of the partnership pursuant to the agreements between the parties.


11.	Asset Retirement Obligations (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations (ARO)

Exelon, Generation and AmerGen have legal obligations to decommission their nuclear power plants following the expiration of their operating licenses. Exelon, Generation and AmerGen will pay for their respective obligations using trust funds that have been established for this purpose.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2007 to June 30, 2007:


	Exelon and Generation

Nuclear decommissioning AROs at January 1, 2007	$	3,533
Accretion expense		115
Payments to decommission retired plants		(4	)

Nuclear decommissioning AROs at June 30, 2007	$	3,644

Exelon and Generation update their nuclear decommissioning AROs on a periodic basis; however, there were no changes in the underlying assumptions that would result in a significant change to the estimated future cash flows during the six months ended June 30, 2007.

During the second quarter of 2006, Generation recorded a net decrease in the ARO of approximately $604 million and pre-tax income of $149 million resulting from revisions to estimated future nuclear decommissioning cash flows, primarily due to revised management assumptions concerning an increased likelihood of successful nuclear license renewal efforts due to an increasingly favorable environment for nuclear power and, therefore, an increased likelihood of operating the nuclear plants through a full license extension period, and also due to a change in management’s expectation of when the U.S. Department of Energy (DOE) will establish a repository for and begin accepting spent nuclear fuel. The recognition of other operating income by Exelon and Generation of $149 million (pre-tax) was included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2006, representing the reduction in the ARO in excess of the existing ARC balance primarily for the AmerGen units.

Nuclear Decommissioning Trust Fund Investments

The trust funds that have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations were originally funded with amounts collected from customers. Certain of these trust funds will continue to be funded by future collections from PECO customers.

At June 30, 2007 and December 31, 2006, Exelon and Generation had nuclear decommissioning trust fund investments totaling $6,777 million and $6,415 million, respectively.

At June 30, 2007, Exelon and Generation had gross unrealized gains of $1,532 million, related to the nuclear decommissioning trust fund investments, of which $1,218 million associated with the former ComEd and former PECO trusts was included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and in noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets. The remaining $314 million gross unrealized gains associated with the unregulated portions of Peach Bottom and AmerGen trusts are included in accumulated OCI on Exelon’s and Generation’s Consolidated Balance Sheets. At December 31, 2006, Exelon and Generation had gross unrealized gains of $1,287 million, related to the nuclear decommissioning trust fund investments, of which $1,037 million associated with the former ComEd and former PECO trusts was included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and in noncurrent payables to affiliates on Generation’s

Consolidated Balance Sheets. The remaining $250 million gross unrealized gains associated with the unregulated portions of Peach Bottom and AmerGen trusts are included in accumulated OCI on Exelon’s and Generation’s Consolidated Balance Sheets. Exelon and Generation consider all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain Nuclear Regulatory Commission restrictions, Exelon and Generation are unable to demonstrate the ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and accordingly recognize any unrealized holding losses immediately. For the three months ended June 30, 2007, Generation recorded impairment charges totaling $12 million, $1 million and $1 million associated with the nuclear decommissioning trust funds for the former ComEd, the former PECO and the AmerGen units, respectively. For the six months ended June 30, 2007, Generation recorded impairment charges totaling $20 million, $1 million and $3 million associated with the nuclear decommissioning trust funds for the former ComEd, the former PECO and the AmerGen units, respectively. Generation recorded impairment charges totaling $7 million and $10 million associated with the nuclear decommissioning trust funds for the former ComEd units for the three and six months ended June 30, 2006, respectively.

As a result of the sale of nuclear decommissioning trust fund investments, Exelon and Generation realized net gains of $10 million and $19 million for the three and six months ended June 30, 2007, respectively, and realized net losses of $9 million and $11 million for the three and six months ended June 30, 2006, respectively, on nuclear decommissioning trust funds.

Refer to Notes 9 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for a full discussion of the accounting for nuclear decommissioning obligations, nuclear decommissioning trust funds and the corresponding accounting implications resulting from agreements entered into with ComEd and PECO at the time of the corporate restructuring effective January 1, 2001. In addition, see Note 16 — Related Party Transactions for information regarding 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.


12.	Earnings Per Share and Shareholders’ 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 long-term incentive plans considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	Three Months					Six Months
	Ended					Ended
	June 30,					June 30,
	2007			2006		2007		2006

Income from continuing operations	$	703		$	641	$	1,384	$	1,041
Income (loss) from discontinued operations		(1	)		3		9		3

Net income	$	702		$	644	$	1,393	$	1,044

Average common shares outstanding — basic		675			670		674		669
Assumed exercise of stock options, performance share awards and restricted stock		5			6		5		6

Average common shares outstanding — diluted		680			676		679		675

There were no stock options excluded from the calculation of diluted common shares outstanding due to their antidilutive effect for the three and six months ended June 30, 2007. The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 4 million for the three and six months ended June 30, 2006, respectively.

Share Repurchases

In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. See Note 16 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information regarding Exelon’s share repurchase program. Repurchased shares are held as treasury shares and recorded at cost. As of June 30, 2007, 13 million shares of common stock have been purchased under the share repurchase program for $652 million. During the six months ended June 30, 2007 and 2006, Exelon repurchased 0.6 million shares and 0.9 million shares, respectively, of common stock under the share repurchase program for $37 million and $53 million, respectively.

Long-Term Incentive Plans

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Income and Comprehensive Income during the three and six months ended June 30, 2007 and 2006:


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
	2007		2006		2007		2006

Stock options	$	7	$	8	$	22	$	25
Performance shares		19		20		36		41
Restricted stock units		2		1		8		2
Employee stock purchase plan		1		1		1		1

Total stock-based compensation included in operating and maintenance expense		29		30		67		69
Income tax benefit		12		11		27		26

Total after-tax stock-based compensation expense	$	17	$	19	$	40	$	43

Stock Options and Performance Shares

For information regarding stock options and performance shares, see Notes 1 and 16 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K.

Restricted Stock Units

Beginning in January 2007, Exelon began granting key managers restricted stock units in lieu of stock options through its long-term incentive plans. During the three and six months ended June 30, 2007, Exelon granted 0 and 331,745 restricted stock units, respectively, which will vest and settle over a three-year period. Prior to 2007, Exelon utilized restricted stock on a limited basis primarily to compensate executive management.

In accordance with SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R), the cost of services received from employees in exchange for the issuance of restricted stock units is required to be measured

based on the grant-date fair value of the restricted stock unit issued. The value of the restricted stock units at the date of grant is either amortized through expense over the requisite service period using the straight-line method or capitalized. For non-retirement eligible individuals, the substantive service period was determined to be the three-year vesting period. The cost associated with restricted stock units granted to employees who are retirement eligible is recognized immediately upon the date of grant, as the employees are not required to render any further service to earn the restricted stock units. For employees who become retirement eligible during the vesting period, the cost of the restricted stock units is recognized on a straight-line basis from the grant date until they become retirement eligible.

The holders of the restricted stock units will be issued shares of common stock annually during the vesting period of three years. During the three and six months ended June 30, 2007, Exelon had costs of $2 million and $7 million, respectively, related to restricted stock units granted to key managers in lieu of stock options.


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

For information regarding capital commitments and nuclear decommissioning at December 31, 2006, see Notes 13 and 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K. All significant contingencies are disclosed below.

Energy Commitments

Generation’s long-term commitments relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as of June 30, 2007 did not change significantly from December 31, 2006, except for the following:


	•	Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others decreased by approximately $760 million during the six months ended June 30, 2007, reflecting increases of approximately $819 million, $495 million and $124 million related to 2008, 2009 and 2010 sales commitments, respectively, offset by the fulfillment of approximately $2,198 million of 2007 commitments during the six months ended June 30, 2007. The increases were primarily due to increased forward sales of energy to counterparties other than ComEd as a result of the expiration of the PPA with ComEd on December 31, 2006, as well as increased overall hedging activity in the normal course of business.

	•	On April 4, 2007, Generation agreed to sell its rights to 942 MWs of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a tolling agreement with Georgia Power, a subsidiary of Southern Company, commencing June 1, 2010 and lasting for 15 or 20 years. The transaction between Generation and Georgia Power is subject to approval by the Georgia Public Service Commission (GPSC). Upon approval of the transaction by the GPSC, Exelon and Generation will recognize a non-cash after-tax loss of up to $75 million. Generation expects to receive approval from the GPSC during the third quarter of 2007. The transaction provides Generation with approximately $43 million in annual revenue in the form of capacity payments over the term of the tolling agreement.

As a result of the first reverse-auction competitive bidding process, ComEd is procuring substantially all of its supply under supplier forward contracts with various suppliers. See Note 4 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information.

Fuel Purchase Obligations

Generation’s and PECO’s fuel purchase obligations as of June 30, 2007 did not change significantly from December 31, 2006, except for the following:


	•	Generation’s total fuel purchase obligations for nuclear and fossil generation as of June 30, 2007 increased by $108 million, $120 million, $95 million, $102 million, and $293 million for 2008, 2009, 2010, 2011, 2012 and beyond, respectively, as compared to December 31, 2006 due to contracts entered into in the normal course of business.

	•	PECO’s total fuel purchase obligations increased by approximately $134 million during the six months ended June 30, 2007, reflecting an increase of $18 million, $63 million, $34 million and $19 million in 2007, 2008, 2009 and 2010, respectively, primarily related to the purchase of natural gas and related transportation services.

Commercial and Construction Commitments

Exelon’s, Generation’s, ComEd’s and PECO’s commercial commitments as of June 30, 2007, representing commitments potentially triggered by future events, did not change significantly from December 31, 2006, except for the following:


	•	Exelon’s letters of credit increased $42 million and guarantees increased by $209 million primarily as a result of leasing activities, energy trading and performance guarantees.

	•	Generation’s letters of credit increased by $41 million and its guarantees increased by $176 million primarily as a result of energy trading activities and the performance guaranty agreement entered into in connection with the sale of TEG and TEP.

Under their operating agreements with PJM, ComEd and PECO are committed to construct transmission facilities. ComEd and PECO will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd’s and PECO’s estimated commitments are as follows:


			July to
			December
	Total		2007		2008		2009		2010		2011		2012

ComEd	$	151	$	64	$	32	$	9	$	13	$	15	$	18
PECO		151		4		28		58		28		26		7

Rate Relief Commitments

In connection with the Settlement agreement reached on July 24, 2007 between legislative leaders in Illinois, ComEd, Generation and other utilities and generators in Illinois, Exelon has committed to contributing approximately $800 million to rate relief programs over four years and funding for the Illinois Power Agency. ComEd will continue to execute upon its $64 million rate relief package announced April 23, 2007, whereby $11 million of rate relief credits had been provided by ComEd to its customers prior to June 14, 2007. Generation would contribute an aggregate of up to $747 million, of which $435 million would be available to reimburse ComEd for rate relief programs for ComEd customers, $307.5 million would be available for rate relief programs for customers of other Illinois utilities, and $4.5 million would be available for funding operations of the Illinois Power Agency. The

following table shows the $800 million to be contributed to rate relief by Generation and ComEd by year. See Note 5 — Regulatory Issues for more information.


			June 14 to		July to
			June 30,		December
	Total		2007(a)		2007		2008		2009		2010

Generation	$	747	$	—	$	426	$	212	$	95	$	14
ComEd(a)		53		7		26		10		10		—

Total	$	800	$	7	$	452	$	222	$	105	$	14


(a)		During the six months ended June 30, 2007, ComEd has credited approximately $18 million to its customers, including $11 million prior to June 14, 2007.

Nuclear Insurance

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due accidents or acts of terrorism. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as extended, as a result of government indemnity. Generally, a “certified act of terrorism” is defined in the Terrorism Risk Insurance Act to be an act of terrorism committed on behalf of a foreign person or interest, as certified by the U.S. government. The Terrorism Risk Insurance Act expires on December 31, 2007, which, if not extended, could have an impact on the insurance coverages available to Generation. Additionally, the expiration of the Terrorism Risk Insurance Act could have an impact on the non-nuclear insurance coverages available to the Registrants.

Refer to Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for a full discussion of nuclear insurance.

Environmental Liabilities

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. ComEd and PECO have identified 42 and 27 sites, respectively, where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several Potentially Responsible Parties (PRPs), which may be responsible for ultimate remediation of each location. Of these 42 sites identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of 9 sites and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection has approved the cleanup of 13 sites. Of the remaining sites identified by ComEd and PECO, 20 and 9 sites, respectively, are currently under some degree of active study and/or remediation. ComEd and PECO anticipate that

the majority of the remediation at these sites will continue through at least 2015 and 2013, respectively. 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 and Nicor Gas Company, a subsidiary of Nicor Inc. (Nicor), are parties to an interim agreement under which they cooperated in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, may have responsibility. Under the interim agreement, costs were split evenly between ComEd and Nicor pending their final agreement on allocation of costs at each site. For most of the sites, the interim agreement contemplated that neither party would pay less than 20%, or more than 80% of the final costs for each site. Through June 30, 2007, ComEd has incurred approximately $110 million associated with remediation of the sites in question. On April 17, 2006, Nicor submitted a demand for arbitration of the cost allocation for 38 MGP sites. In July 2007, ComEd and Nicor reached an agreement on the allocation of costs for the MGP sites. The agreement is contingent upon ICC approval and the execution of definitive written agreements. ComEd’s accrual as of June 30, 2007 for these environmental liabilities has been adjusted to reflect the cost allocations contemplated in the agreement.

Based on the final order received in ComEd’s Rate Case, beginning in 2007, ComEd is recovering MGP remediation costs from customers for which it established a regulatory asset. Pursuant to a PAPUC order, PECO is currently recovering a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. See Note 14 — Supplemental Financial Information for further information regarding regulatory assets and liabilities.

As of June 30, 2007 and December 31, 2006, Exelon, Generation, ComEd and PECO had accrued the following amounts for environmental liabilities:


	Total
	Environmental
	Investigation and		Portion of Total Related
	Remediation		to MGP Investigation
June 30, 2007	Reserve		and Remediation

Exelon	$	127	$	101
Generation		17		—
ComEd		72		65
PECO		38		36


	Total
	Environmental
	Investigation and		Portion of Total Related
	Remediation		to MGP Investigation
December 31, 2006	Reserve		and Remediation

Exelon	$	119	$	88
Generation		20		—
ComEd		58		49
PECO		41		39

The Registrants cannot predict the extent to which they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by environmental agencies or others, or whether such costs may be recoverable from third parties.

Section 316(b) of the Clean Water Act

In July 2004, the United States Environmental Protection Agency (EPA) issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule established national performance standards for reducing entrainment and impingement of aquatic organisms at existing power plants. The rule provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’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. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Since promulgation of the rule, Generation has been evaluating compliance options at each of its affected plants to achieve interim compliance deadlines.

On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in a challenge to the final Phase II rule brought by environmental groups and several states. The court found that, with respect to a number of significant provisions of the rule, the EPA either exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the rule back to the EPA for revisions consistent with the court’s opinion. By its action, the court invalidated compliance measures that the utility industry supported because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. For example, the court found that environmental restoration does not qualify as a compliance option and site-specific compliance variances based on a cost-benefit analysis are impermissible.

The court’s decision has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. Several industry parties to the litigation sought review by the entire U.S. Court of Appeals for the Second Circuit, which was denied on July 5, 2007. Parties to the litigation have until October 3, 2007 to file a petition seeking review by the U.S. Supreme Court. On July 9, 2007, the EPA formally suspended the Phase II rule due to the uncertainty about the specific compliance requirements created by the court’s remand of significant provisions of the rule. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures. Due to this uncertainty, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. If the final rule, or interim state requirements under best professional judgment, have performance standards that require the reduction of cooling water intake flow at the plants consistent with closed loop cooling systems, then the impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, financial position and cash flows could be material.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the NPDES permit renewal process for Oyster Creek that has been pending since 1999, the New Jersey Department of Environmental Protection (NJDEP) preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. The final permit has not been issued, and Oyster Creek has continued to operate under the 1999 permit. Generation cannot predict with any certainty how the NJDEP will implement its best professional judgment. AmerGen has not made a determination regarding how it will comply with the Section 316(b) regulations and must first evaluate the final regulations issued by the EPA as a result of the decision of the U.S. Court of Appeals for the Second Circuit,

discussed above. In addition, the cost required to retrofit Oyster Creek with closed cycle cooling could be material and could therefore negatively impact Generation’s decision to renew the plant’s operating license.

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. The NPDES permit expired in July 2006. NJDEP advised Public Service Enterprise Group Incorporated (PSEG), the plant operator, in a letter dated July 12, 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, along with continued operation of the existing intake, is the best available 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. PSEG must evaluate the final Phase II rule after remand, particularly whether the restoration done under the Estuary Enhancement Project remains a compliance option. If application of the final Section 316(b) regulations or the NJDEP as a result of the Phase II ruling discussed above ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

Nuclear Generating Station Groundwater

On December 16, 2005 and February 27, 2006, the Illinois EPA issued violation notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station (Braidwood). In November 2005, Generation discovered that spills from the line in 1996, 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels in portions of the plume exceed Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant showed that, with one exception, tritium levels in these wells were at levels that naturally occur. The tritium level in one drinking water well was elevated above levels that occur naturally, but was significantly below the state and Federal drinking water standards, and Generation believes that this level posed no threat to human health. Generation has investigated the causes of the releases and has taken the necessary corrective actions to prevent another occurrence. Generation notified the owners of 14 potentially affected adjacent properties that, upon sale of their property, Generation will reimburse the owners for any diminution in property value caused by the tritium release. As of June 30, 2007, Generation has purchased four of the 14 adjacent properties.

On March 13, 2006, a class action lawsuit was filed against Exelon, Generation and ComEd (as the prior owner of Braidwood) in Federal District Court for the Northern District of Illinois on behalf of all persons who live or own property within 10 miles of Braidwood. Initially, the plaintiffs primarily sought compensation for diminished property values, but in February 2007, they amended their complaint to seek punitive damages. The U.S. District Court for the Northern District of Illinois denied the class action status of the lawsuit on March 19, 2007. Plaintiffs requested reconsideration and sought certification of a class of approximately 200 persons whose property allegedly had tritium at levels below detection level, along with a class of adjacent property owners (unspecified in number) that had allegedly been affected by tritium from the plant. On June 8, 2007, the plaintiffs voluntarily dismissed the lawsuit with prejudice.

On March 14 and 23, 2006, 37 area residents filed two separate but identical lawsuits against Exelon, Generation and ComEd in the Circuit Court of Will County, Illinois alleging property contamination and seeking compensation for diminished property values. Exelon removed these cases to Federal court, and all three cases were

assigned to the same District Court judge. Subsequently, seven plaintiffs withdrew from the cases, and 18 additional plaintiffs were added. On May 17, 2007, the plaintiffs voluntarily dismissed the cases without prejudice. On October 11, 2006, two area residents filed a lawsuit in the U.S. District Court for the Northern District of Illinois against Exelon, Generation and ComEd. The allegations in the complaint are substantially similar to the lawsuits described above, and the case has been transferred to the judge overseeing the other Federal cases. This is the only remaining lawsuit brought by local residents. Exelon, Generation and ComEd have tendered the defense for this lawsuit to their insurance carrier, ANI, and ANI has agreed to defend the suit subject to a reservation of rights. Exelon, Generation and ComEd continue to believe that this lawsuit is without merit and will continue to vigorously oppose it.

On March 16, 2006, the Attorney General of the state of Illinois and the State’s Attorney for Will County, Illinois filed a civil enforcement action against Exelon, Generation and ComEd in the Circuit Court of Will County relating to the releases of tritium discussed above and alleging that, beginning on or before 1996, and with additional events in 1998, 2000 and 2005, there have been tritium and other non-radioactive wastes discharged from Braidwood in violation of Braidwood’s NPDES permit, the Illinois Environmental Protection Act and regulations of the Illinois Pollution Control Board. The lawsuit seeks injunctive relief relating to the discontinuation of the liquid tritium discharge line until further court order, soil and groundwater testing, prevention of future releases and off-site migration and to provide potable drinking water to area residents. The action also seeks the maximum civil penalties allowed by the statute and regulations, $10,000 or $50,000 for each violation (depending on the specific violation), and $10,000 for each day during which a violation continues. On May 24, 2006, the Circuit Court of Will County, Illinois entered an order resulting in Generation commencing remediation efforts in June 2006 for tritium in groundwater off of plant property. Among other things, the May 24, 2006 order requires Generation to conduct certain studies and implement measures to ensure that tritium does not leave plant property at levels in excess of the United States EPA safe drinking water standard. Any civil penalty will not be determined until the consent decree is finalized. Furthermore, the Circuit Court of Will County may exercise its discretion in determining the final penalty, if any, taking into account a number of factors, including corrective actions taken by Generation and other mitigating circumstances.

As of June 30, 2007 and December 31, 2006, Generation had reserves of $2 million and $3 million, respectively, related to the matters described above, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

As a result of intensified monitoring and inspection efforts in 2006, Generation detected small underground tritium leaks at the Dresden Nuclear Generating Station (Dresden) and at the Byron Nuclear Generating Station (Byron). Neither of these discharges occurred outside the property lines of the plant, nor does Generation believe either of these matters poses health or safety threats to employees or to the public. Generation identified the source of the leaks and implemented repairs. On March 31, 2006 and April 12, 2006, the Illinois EPA issued a violation notice to Generation in connection with the Dresden and Byron leaks, respectively, alleging various violations, including those related to (1) Illinois groundwater standards, (2) non-permitted discharges, and (3) each station’s NPDES permit. Generation has analyzed the remediation options related to these matters and submitted its response and proposed remediation plan to the Illinois EPA. On July 10, 2006, the Illinois EPA rejected the remediation plan for Dresden and on July 12, 2006, the Illinois EPA sent a Notice of Intention to Pursue Legal Action. On July 17, 2006, the Illinois EPA rejected the remediation plan for Byron and has referred the matter to the Illinois Attorney General for consideration of formal enforcement action and the imposition of penalties.

Generation is actively discussing the violation notices and Attorney General civil enforcement matters for Braidwood, Dresden and Byron, discussed above, with the Illinois EPA and the Attorneys General for Illinois and the Counties in which the plants are located. While Generation is unable to determine the amount of the civil

penalties that will be included in a final consent decree, it is probable that they will exceed $100,000 in the aggregate for all three stations but will not be material to Exelon’s and Generation’s financial positions, results of operations and cash flows. Generation expects these matters to be resolved during 2007.

Exelon, Generation or ComEd cannot determine the outcome of the above-described matters but believe their ultimate resolution should not, after consideration of reserves established, have a significant impact on Exelon’s, Generation’s or ComEd’s financial position, results of operations or cash flows.

Cotter Corporation

The 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 incurred by Cotter as a result of 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. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site range up to $24 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.

Greenhouse Gas Emissions Reductions

Exelon announced on May 6, 2005 that it has established a voluntary goal to reduce its greenhouse gas (GHG) emissions by 8% from 2001 levels by the end of 2008. The 8% reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon will incorporate recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in activities that result in the reduction or avoidance of GHG emissions. Exelon made this pledge under the United States EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. Exelon believes that its planned GHG management efforts, including increased use of renewable energy, its current energy and process efficiency initiatives and its efforts in the areas of carbon sequestration, will allow it to achieve this goal. The anticipated cost of achieving the voluntary GHG emissions reduction goal will not have a material effect on Exelon’s future results of operations, financial condition or cash flows.

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency holding that carbon dioxide and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule and Federal or state legislation. Exelon continues to support the enactment, through federal legislation, of a cap-and-trade system for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and the competitiveness of the manufacturing base in the U.S. Due to the uncertainty as to any of these potential outcomes, Exelon cannot estimate the effect of the decision on its operations and its future results of operations, financial condition and cash flows.

Litigation and Regulatory Matters

Exelon, Generation and PECO

PJM Billing Dispute. In December 2004, Exelon filed a complaint with FERC against PJM and PPL Electric (PPL) alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleged that PJM mistakenly identified PPL’s Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL took from the Elroy substation and used to serve PPL load.

Beginning in September of 2005 and throughout 2006, Exelon and PPL filed multiple settlement proposals with FERC, with each new proposal superceding the prior, in attempts to resolve this matter. On March 20, 2007, FERC issued an order accepting the settlement in which PPL agreed to directly pay Exelon approximately $43 million in a lump-sum payment (comprised of $38 million of erroneous charges, plus interest of $5 million). At that time, Exelon established a receivable due from PPL and recognized the corresponding gain in earnings during the first quarter of 2007. Approximately $32 million and $11 million of the settlement amount were to be received by Generation and PECO, respectively, and recorded as a reduction to purchased power expense and interest income. In April 2007, this receivable amount was paid in full, including interest.

Real Estate Tax Appeals. Generation and PECO each have been challenging real estate taxes assessed on certain nuclear plants. PECO has been involved in litigation in which it has contested taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA), and has appealed local real estate assessments for 1998 and 1999 on the Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom). On March 27, 2007, PECO prevailed in a unanimous decision by the Pennsylvania Supreme Court in its contesting of taxes assessed in 1997 under PURTA. The Commonwealth of Pennsylvania (Commonwealth) had contended that PECO owed more in real estate taxes in 1997 than had previously been remitted by PECO, while PECO contended that it owed less than what it had previously remitted. PECO received a favorable ruling in this case, which resulted in a credit to PECO of approximately $38 million of real estate taxes previously remitted. That credit was received in May 2007. PECO also received a credit for approximately $17 million in interest from the Commonwealth in July 2007. PECO had previously reserved approximately $17 million for the difference between the Commonwealth’s assessment and the amount previously remitted by PECO. This reserve was reversed as a result of the favorable ruling PECO received. PECO is in the process of determining the ultimate use and ratemaking treatment of these amounts and has recorded the total of these amounts of $72 million as a regulatory liability. The balance of this regulatory liability as of June 30, 2007 is $71 million, which also reflects $1 million in legal costs already incurred in connection with the tax recovery. See Note 14 — Supplemental Financial Information for a listing of PECO’s regulatory assets and liabilities.

As of June 30, 2007, Generation was involved in real estate tax appeals for the 2005 and 2006 tax years concerning the value of its Byron plant for real estate tax purposes. Also, Generation was involved in real estate tax appeals and related litigation for the 2006 tax year concerning the value for real estate tax purposes of its Braidwood, Clinton and Dresden plants. The ultimate outcome of these matters remains uncertain and could result in unfavorable or favorable impacts to the consolidated financial statements of Exelon, Generation and PECO. Generation and PECO believe their reserve balances for exposures associated with real estate taxes as of June 30, 2007 reflect their best estimates of the probable outcome of these appeals and related proceedings in accordance with SFAS No. 5.

Exelon and Generation

Asbestos Personal Injury Claims. In the second quarter of 2005, Generation engaged independent actuaries to determine if, based on historical claims data and other available information, a reasonable estimate of future losses could be calculated associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. Based on the actuaries’ analyses, management’s review of current and expected losses, and the view of counsel regarding the assumptions used in estimating the future losses, Generation recorded an undiscounted $43 million pre-tax charge for its estimated portion of all estimated future asbestos-related personal injury claims estimated to be presented through 2030. This amount did not include estimated legal costs associated with handling these matters, which could be material. Generation’s management determined that it was not reasonable to estimate future asbestos-related personal injury claims past 2030 based on only three years of historical claims data and the significant amount of judgment required to estimate this liability. The $43 million pre-tax charge was recorded as part of operating and maintenance expense in Generation’s Consolidated Statements of Operations and Comprehensive Income in 2005 and reduced net income by $27 million after tax.

At June 30, 2007 and December 31, 2006, Generation had reserved approximately $51 and $48 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2007, approximately $12 million of this amount relates to 144 open claims presented to Generation, while the remaining $39 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Generation obtains annual actuarial study updates of the estimate of future losses. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments. During 2006 and the first and second quarters of 2007, Generation performed periodic updates to this reserve, which did not result in a material adjustment.

Oil Spill Liability Trust Fund Claim. In December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River near the facilities. The units, which draw water from the river for cooling purposes, were taken offline for approximately two weeks to avoid intake of the spilled oil and for an additional two weeks relating to start up issues arising from the oil spill shutdown. The total shutdown period resulted in lost sales from the plant. Generation and PSEG subsequently filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund. In January 2007, Generation and PSEG submitted a revised damages calculation to the Oil Spill Liability Trust Fund identifying approximately $46 million in total damages and losses, of which approximately $20 million would be paid to Exelon. As this matter represents a contingent gain, Generation has not recorded any income. Generation expects this matter to be resolved in 2007.

Supply Agreement Non-performance Claims. Generation enters into long-term supply agreements to procure uranium concentrates. In 2007, Generation initiated claims asserting non-performance by certain counterparties. As a result of this non-performance, Generation will be required to procure uranium concentrates at higher prices than originally anticipated. Generation has filed suit against two counterparties asserting breach of uranium supply agreement against one counterparty and breach of performance guarantee and fraudulent inducement against the other counterparty. As these matters represent contingent gains, Generation has not recorded any income. The cases are scheduled for trial in 2008.

Exelon

Pension Claim. On July 11, 2006, a former employee of ComEd filed a purported class action lawsuit against the Exelon Corporation Cash Balance Pension Plan (Plan) in the U.S. District Court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculates lump sum distributions in a manner that does not comply with the Employee Retirement Income Security

Act (ERISA). The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions since 2001 and injunctive relief with respect to future lump sum distributions. It remains to be determined whether this case will proceed as a class action and how many Plan participants may be part of the proposed class, if a class is certified.

Savings Plan Claim. On September 11, 2006, five individuals claiming to be participants in the Exelon Corporation Employee Savings Plan, Plan #003 (Savings Plan), filed a putative class action lawsuit in the United States District Court for the Northern District of Illinois. The complaint names as defendants Exelon, its Director of Employee Benefit Plans and Programs, the Employee Savings Plan Investment Committee, the Compensation and the Risk Oversight Committees of Exelon’s Board of Directors and members of those committees. The complaint alleges that the defendants breached fiduciary duties under ERISA by, among other things, permitting fees and expenses to be incurred by the Savings Plan that allegedly were unreasonable and for purposes other than to benefit the Savings Plan and participants, and failing to disclose purported “revenue sharing” arrangements among the Savings Plan’s service providers. The plaintiffs seek declaratory, equitable and monetary relief, including alleged investment losses. On February 21, 2007 the district court granted the defendants’ motion to strike the plaintiffs’ claim for investment losses. On June 27, 2007, the district court granted the plaintiffs’ motion for class certification. On June 28, 2007, the district court granted the defendants’ motion to stay proceedings in this action pending the outcome of the forthcoming appeal to the U.S. Seventh Circuit Court of Appeals in another case not involving Exelon. In that case, an appeal is expected to be taken from the June 20, 2007 decision of the U.S. District Court for the Western District of Wisconsin, which dismissed with prejudice substantially similar claims.

Exelon, Generation, ComEd and PECO

General. The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on the Registrants’ financial condition, results of operations or cash flows.

Fund Transfer Restrictions

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs. See Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for additional information regarding fund transfer restrictions.

Income Taxes

ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash impacts to ComEd and

PECO related to these agreements and the associated refund claims will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. If a settlement is reached, a portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO/Unicom merger, would be recorded as a reduction of goodwill under the provisions of EITF 93-7. Exelon cannot predict the timing of the final resolution of these refund claims or the potential payment of any contingent fees.

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.


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

Supplemental Statement of Operations Information

The following tables provide additional information regarding the components of other, net within the Consolidated Statements of Operations and Comprehensive Income of Exelon, Generation, ComEd and PECO for the three and six months ended June 30, 2007 and 2006:


	Three Months Ended June 30, 2007
	Exelon			Generation			ComEd		PECO

Investment income	$	3		$	—		$	1	$	2
Gain on disposition of assets and investments, net		4			3			1		—
Decommissioning-related activities:
Decommissioning trust fund income(a)		58			58			—		—
Decommissioning trust fund income — AmerGen(a)		15			15			—		—
Other-than-temporary impairment of decommissioning trust funds(b)		(12	)		(12	)		—		—
Other-than-temporary impairment of decommissioning trust funds — AmerGen		(2	)		(2	)		—		—
Regulatory offset to non-operating decommissioning-related activities(c)		(45	)		(45	)		—		—
Net direct financing lease income		4			—			—		—
AFUDC, equity		1			—			1		—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities(d)		9			—			—		—
Interest income related to uncertain income tax positions under FIN 48(e)		—			—			—		2
Other		8			5			2		1

Other, net	$	43		$	22		$	5	$	5


(a)		Includes investment income and realized gains and losses.

(b)		Includes other-than-temporary impairments totaling $12 million on nuclear decommissioning trust funds for the former ComEd units.

(c)		Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments. See


		Notes 9 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(d)		Receivable for the contractual recovery of unrealized income tax credits related to Exelon’s investment in synthetic fuel-producing facilities. See Note 10 — Income Taxes for additional information.

(e)		See Note 3 — New Accounting Pronouncements and Note 10 — Income Taxes for additional information.


	Six Months Ended June 30, 2007
	Exelon			Generation			ComEd		PECO

Investment income	$	5		$	—		$	2	$	3
Gain on disposition of assets and investments, net		19			18			1		—
Decommissioning-related activities:
Decommissioning trust fund income(a)		104			104			—		—
Decommissioning trust fund income — AmerGen(a)		26			26			—		—
Other-than-temporary impairment of decommissioning trust funds(b)		(20	)		(20	)		—		—
Other-than-temporary impairment of decommissioning trust funds — AmerGen		(4	)		(4	)		—		—
Regulatory offset to non-operating decommissioning-related activities(c)		(82	)		(82	)		—		—
Net direct financing lease income		10			—			—		—
AFUDC, equity		2			—			2		—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities(d)		29			—			—		—
Interest income related to settlement of PJM billing dispute(e)		5			4			—		1
Interest income related to uncertain income tax positions under FIN 48(f)		—			—			—		5
Other		12			8			2		1

Other, net	$	106		$	54		$	7	$	10


(a)		Includes investment income and realized gains and losses.

(b)		Includes other-than-temporary impairments totaling $20 million on nuclear decommissioning trust funds for the former ComEd units.

(c)		Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments. See Notes 9 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(d)		Receivable for the contractual recovery of unrealized income tax credits related to Exelon’s investment in synthetic fuel-producing facilities. See Note 10 — Income Taxes for additional information.

(e)		See Note 13 — Commitments and Contingencies for additional information.

(f)		See Note 3 — New Accounting Pronouncements and Note 10 — Income Taxes for additional information.


	Three Months Ended June 30, 2006
	Exelon			Generation			ComEd			PECO

Investment income	$	2		$	—		$	—		$	2
Loss on disposition of assets and investments, net		(3	)		—			(2	)		(1	)
Decommissioning-related activities:
Decommissioning trust fund income(a)		37			37			—			—
Decommissioning trust fund income — AmerGen(a)		10			10			—			—
Other-than-temporary impairment of decommissioning trust funds(b)		(7	)		(7	)		—			—
Regulatory offset to non-operating decommissioning-related activities(c)		(31	)		(31	)		—			—
Net direct financing lease income		6			—			—			—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities(d)		24			—			—			—
Other		8			5			3			1

Other, net	$	46		$	14		$	1		$	2


(a)		Includes investment income and realized gains and losses.

(b)		Includes other-than-temporary impairments totaling $7 million on nuclear decommissioning trust funds for the former ComEd units.

(c)		Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments. See Notes 9 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(d)		Receivable for the contractual recovery of unrealized income tax credits related to Exelon’s investment in synthetic fuel-producing facilities. See Note 10 — Income Taxes for further information.


	Six Months Ended June 30, 2006
	Exelon			Generation			ComEd			PECO

Investment income	$	4		$	—		$	—		$	4
Loss on disposition of assets and investments, net		(2	)		—			(2	)		—
Decommissioning-related activities:
Decommissioning trust fund income(a)		66			66			—			—
Decommissioning trust fund income — AmerGen(a)		19			19			—			—
Other-than-temporary impairment of decommissioning trust funds(b)		(10	)		(10	)		—			—
Regulatory offset to non-operating decommissioning-related activities(c)		(57	)		(57	)		—			—
Net direct financing lease income		12			—			—			—
Unrealized income tax credits(d)		53			—			—			—
Other		6			2			3			1

Other, net	$	91		$	20		$	1		$	5


(a)		Includes investment income and realized gains and losses.

(b)		Includes other-than-temporary impairments totaling $10 million on nuclear decommissioning trust funds for the former ComEd units.

(c)		Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments. See Notes 9 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(d)		Receivable for the contractual recovery of unrealized income tax credits related to Exelon’s investment in synthetic fuel-producing facilities. See Note 10 — Income Taxes for further information.

Supplemental Cash Flow Information

The following tables provide additional information regarding the components of other non-cash operating activities and other assets and liabilities within the Registrants’ Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006:


	Six Months Ended June 30, 2007
	Exelon			Generation			ComEd			PECO

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	157		$	71		$	51		$	16
Equity in (earnings) losses of unconsolidated affiliates and investments		69			(1	)		4			4
Provision for uncollectible accounts		44			—			24			20
Stock-based compensation costs		41			—			—			—
Net realized gains on nuclear decommissioning trust funds		(19	)		(19	)		—			—
Gain on sale of investments, net		(18	)		(18	)		—			—
Amortization of energy-related options		66			66			—			—
Non-cash accounts receivable activity		(25	)		—			—			—
Spent nuclear fuel expense		24			24			—			—
Amortization of regulatory asset related debt costs		16			—			13			3
Other		14			7			15			4

Total other non-cash operating activities	$	369		$	130		$	107		$	47

Changes in other assets and liabilities:
Under/over-recovered energy costs	$	(96	)	$	—		$	(104	)	$	8
Other current assets		(198	)		(91	)(a)		—			(86	)(b)
Other noncurrent assets and liabilities		(53	)		(55	)(a)		11			1

Total changes in other assets and liabilities	$	(347	)	$	(146	)	$	(93	)	$	(77	)


(a)		Relates primarily to the purchase of energy-related options.

(b)		Relates primarily to prepaid utility taxes.


	Six Months Ended June 30, 2006
	Exelon			Generation			ComEd			PECO

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	125		$	57		$	38		$	15
Equity in losses of unconsolidated affiliates and investments		61			5			5			6
Provision for uncollectible accounts		42			—			11			31
Stock-based compensation costs		53			—			—			—
Amortization of energy-related options		39			39			—			—
Amortization of deferred revenue		(34	)		(34	)		—			—
Non-cash accounts receivable activity		(57	)		—			—			—
Spent nuclear fuel expense		20			20
Other decommissioning-related activities		(149	)		(149	)		—			—
Amortization of regulatory asset related debt costs		7			—			5			2
Other		17			6			13			7

Total other non-cash operating activities	$	124		$	(56	)	$	72		$	61

Changes in other assets and liabilities:
Under/over-recovered energy costs	$	61		$	—		$	—		$	61
Other current assets		(197	)		(70	)(a)		(10	)		(84	)(b)
Other noncurrent assets and liabilities		(159	)		(148	)(a)		3			3

Total changes in other assets and liabilities	$	(295	)	$	(218	)	$	(7	)	$	(20	)


(a)		Relates primarily to the purchase of energy-related options.

(b)		Relates primarily to prepaid utility taxes.

Supplemental Balance Sheet Information

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of June 30, 2007 and December 31, 2006:


	June 30, 2007
	Exelon		ComEd		PECO

Regulatory assets
Competitive transition charge	$	2,688	$	—	$	2,688
Pension and other postretirement benefits		1,352		—		36
Deferred income taxes		806		11		795
Debt costs		193		166		27
Severance		147		147		—
Conditional asset retirement obligations		112		98		14
MGP remediation costs		80		59		21
Rate case costs		6		6		—
Department of Energy facility decommissioning		3		—		3
Procurement case costs		4		4		—
Other		47		28		19

Noncurrent regulatory assets		5,438		519		3,603
Under-recovered energy costs current asset(a)		104		104		—

Total regulatory assets	$	5,542	$	623	$	3,603


	June 30, 2007
	Exelon		ComEd		PECO

Regulatory liabilities
Nuclear decommissioning	$	2,048	$	1,856	$	192
Removal costs		1,077		1,077		—
Deferred taxes		44		—		—
Refund of PURTA taxes(b)		71		—		71

Noncurrent regulatory liabilities		3,240		2,933		263
Over-recovered energy costs current liability(a)		14		—		14

Total regulatory liabilities	$	3,254	$	2,933	$	277


(a)		Starting in 2007, the ComEd costs represent electricity and transmission costs recoverable (refundable) under ComEd’s ICC-approved rates. ComEd’s deferred energy costs are earning (paying) a rate of return. See Note 5 — Regulatory Issues. The PECO costs represent gas supply related costs recoverable (refundable) under PECO’s PAPUC-approved rates. PECO’s deferred energy costs are earning (paying) a rate of return.

(b)		See Note 13 — Commitments and Contingencies for additional information.


	December 31, 2006
	Exelon		ComEd		PECO

Regulatory assets
Competitive transition charge	$	2,982	$	—	$	2,982
Pension and other postretirement benefits		1,419		—		39
Deferred income taxes		801		11		790
Debt costs		209		179		30
Severance		158		158		—
Conditional asset retirement obligations		109		95		14
MGP remediation costs		73		47		26
Rate case costs		7		7		—
Department of Energy facility decommissioning		6		—		6
Procurement case costs		5		5		—
Other		39		30		9

Total regulatory assets	$	5,808	$	532	$	3,896


	December 31, 2006
	Exelon		ComEd		PECO

Regulatory liabilities
Nuclear decommissioning	$	1,911	$	1,760	$	151
Removal costs		1,059		1,059		—
Deferred taxes		50		—		—
Other		5		5		—

Noncurrent regulatory liabilities		3,025		2,824		151
Over-recovered energy costs current liability(a)		6		—		6

Total regulatory liabilities	$	3,031	$	2,824	$	157


(a)		The PECO costs represent gas supply related costs recoverable (refundable) under PECO’s PAPUC-approved rates. PECO’s deferred energy costs are earning (paying) a rate of return.

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of June 30, 2007 and December 31, 2006:


	June 30, 2007
	Exelon			Generation			ComEd		PECO

Property, plant and equipment:
Accumulated depreciation	$	7,442	(a)	$	3,456	(a)	$	1,542	$	2,266
Accounts receivable:
Allowance for uncollectible accounts		110			16			35		57


(a)		Includes accumulated amortization of nuclear fuel of $1,089 million.


	December 31, 2006
	Exelon			Generation			ComEd		PECO

Property, plant and equipment:
Accumulated depreciation	$	7,250	(a)	$	3,414	(a)	$	1,445	$	2,228
Accounts receivable:
Allowance for uncollectible accounts		91			17			20		51


(a)		Includes accumulated amortization of nuclear fuel of $1,078 million.

The following tables provide information regarding counterparty margin deposit accounts and option premiums as of June 30, 2007 and December 31, 2006:


	June 30, 2007
	Exelon		Generation		ComEd

Other current assets:
Counterparty collateral deposits paid	$	257	$	257	$	—
Option premiums		166		166		—
Other current liabilities:
Counterparty collateral deposits received		9		6		3	(a)


(a)		ComEd has received counterparty collateral deposits from suppliers under its supplier forward contracts for the procurement of electricity.


	December 31, 2006
	Exelon and
	Generation

Other current assets:
Counterparty collateral deposits paid	$	26
Option premiums		179
Other current liabilities:
Counterparty collateral deposits received		273

The following table provides information regarding dividends payable as of June 30, 2007 and December 31, 2006:


	June 30,		December 31,
Exelon	2007		2006

Other current liabilities:
Dividends payable	$	1	$	295


15.	Segment Information (Exelon, Generation, ComEd and PECO)

Exelon has three reportable and operating segments: Generation, ComEd and PECO. Exelon evaluates the performance of its segments based on net income. Generation, ComEd and PECO each operate in a single business segment; as such, no separate segment information is provided for these Registrants.

Three Months Ended June 30, 2007 and 2006

Exelon’s segment information for the three months ended June 30, 2007 and 2006 is as follows:


										Intersegment
	Generation		ComEd		PECO		Other(a)			Eliminations			Consolidated

Total revenues(b):
2007	$	2,641	$	1,420	$	1,269	$	183		$	(1,012	)	$	4,501
2006		2,214		1,453		1,148		203			(1,321	)		3,697
Intersegment revenues:
2007	$	828	$	—	$	2	$	183		$	(1,013	)	$	—
2006		1,114		2		2		203			(1,321	)		—
Income (loss) from continuing operations before income taxes:
2007	$	927	$	47	$	151	$	(108	)	$	—		$	1,017
2006		791		213		138		(138	)		—			1,004
Income taxes:
2007	$	349	$	18	$	55	$	(108	)	$	—		$	314
2006		294		86		45		(62	)		—			363
Income (loss) from continuing operations:
2007	$	578	$	29	$	96	$	—		$	—		$	703
2006		497		127		93		(76	)		—			641
Income (loss) from discontinued operations:
2007	$	—	$	—	$	—	$	(1	)	$	—		$	(1	)
2006		3		—		—		—			—			3
Net income (loss):
2007	$	578	$	29	$	96	$	(1	)	$	—		$	702
2006		500		127		93		(76	)		—			644


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(b)		For the three months ended June 30, 2007 and 2006, utility taxes of $60 million and $57 million, respectively, are included in revenues and expenses for ComEd. For the three months ended June 30, 2007 and 2006, utility taxes of $65 million and $58 million, respectively, are included in revenues and expenses for PECO.

Six Months Ended June 30, 2007 and 2006

Exelon’s segment information for the six months ended June 30, 2007 and 2006 is as follows:


										Intersegment
	Generation		ComEd		PECO		Other(a)			Eliminations			Consolidated

Total revenues(b):
2007	$	5,344	$	2,911	$	2,769	$	377		$	(2,071	)	$	9,330
2006		4,434		2,880		2,554		410			(2,719	)		7,559
Intersegment revenues:
2007	$	1,689	$	2	$	4	$	377		$	(2,072	)	$	—
2006		2,302		4		4		409			(2,719	)		—
Income (loss) from continuing operations before income taxes:
2007	$	1,817	$	54	$	345	$	(184	)	$	—		$	2,032
2006		1,219		304		279		(197	)		—			1,605
Income taxes:
2007	$	684	$	21	$	121	$	(178	)	$	—		$	648
2006		454		123		93		(106	)		—			564
Income (loss) from continuing operations:
2007	$	1,133	$	33	$	224	$	(6	)	$	—		$	1,384
2006		765		181		186		(91	)		—			1,041
Income from discontinued operations:
2007	$	5	$	—	$	—	$	4		$	—		$	9
2006		3		—		—		—			—			3
Net income (loss):
2007	$	1,138	$	33	$	224	$	(2	)	$	—		$	1,393
2006		768		181		186		(91	)		—			1,044
Total assets:
June 30, 2007	$	19,035	$	18,466	$	9,933	$	14,856		$	(16,985	)	$	45,305
December 31, 2006		18,909		17,774		9,773		14,295			(16,432	)		44,319


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(b)		For the six months ended June 30, 2007 and 2006, utility taxes of $126 million and $119 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2007 and 2006, utility taxes of $128 million and $115 million, respectively, are included in revenues and expenses for PECO.


16.	Related-Party Transactions (Exelon, Generation, ComEd and PECO)

Exelon

The financial statements of Exelon include related-party transactions as presented in the tables below:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2007			2006			2007			2006

Operating revenues from affiliates
ComEd Transitional Funding Trust	$	1		$	1		$	2		$	2
PETT		1			2			3			4

Total operating revenues from affiliates	$	2		$	3		$	5		$	6

Fuel purchases from related parties
Keystone Fuels, LLC	$	12		$	11		$	21		$	22
Conemaugh Fuels, LLC		9			11			21			22

Total fuel purchases from related parties	$	21		$	22		$	42		$	44

Interest expense to affiliates, net
ComEd Transitional Funding Trust	$	7		$	12		$	15		$	26
ComEd Financing II		4			4			7			7
ComEd Financing III		3			3			6			6
PETT		36			46			75			95
PECO Trust III		1			1			3			3
PECO Trust IV		2			2			3			2

Total interest expense to affiliates, net	$	53		$	68		$	109		$	139

Equity in earnings (losses) of unconsolidated affiliates and investments
ComEd Funding LLC	$	(2	)	$	(3	)	$	(4	)	$	(5	)
PETT		(2	)		(2	)		(4	)		(6	)
TEG and TEP		—			(2	)		3			(4	)
Investment in synthetic fuel-producing facilities		(39	)		(16	)		(63	)		(46	)
Other		—			1			(1	)		—

Total equity in earnings (losses) of unconsolidated affiliates and investments	$	(43	)	$	(22	)	$	(69	)	$	(61	)


	June 30,			December 31,
	2007			2006

Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	—		$	17
Investments in affiliates
ComEd Funding LLC	$	(4	)	$	4
ComEd Financing II		10			10
ComEd Financing III		6			6
PETT		51			54
PECO Energy Capital Corporation		4			4
PECO Trust IV		6			6
Other		—			1

Total investments in affiliates	$	73		$	85

Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust	$	15		$	14
Payables to affiliates (current)
ComEd Financing II	$	6		$	6
ComEd Financing III		4			4
PECO Trust III		1			1

Total payables to affiliates (current)	$	11		$	11

Long-term debt to ComEd Transitional Funding Trust, PETT and other financing trusts (including due within one year)
ComEd Transitional Funding Trust	$	444		$	648
ComEd Financing II		155			155
ComEd Financing III		206			206
PETT		2,050			2,403
PECO Trust III		81			81
PECO Trust IV		103			103

Total long-term debt due to financing trusts	$	3,039		$	3,596

Generation

The financial statements of Generation include related-party transactions as presented in the tables below:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Operating revenues from affiliates
ComEd(a)	$	330		$	685		$	710		$	1,456
PECO(b)		497			429			978			845
BSC(c)		1			—			1			1

Total operating revenues from affiliates	$	828		$	1,114		$	1,689		$	2,302

Fuel purchases from related parties
Keystone Fuels, LLC	$	12		$	11		$	21		$	22
Conemaugh Fuels, LLC		9			11			21			22

Total fuel purchases from related parties	$	21		$	22		$	42		$	44

Operating and maintenance from affiliates
ComEd(d)	$	—		$	2		$	1		$	3
PECO(d)		2			2			4			4
BSC(c)		71			74			146			146

Total operating and maintenance from affiliates	$	73		$	78		$	151		$	153

Interest expense to affiliates, net
Exelon intercompany money pool(e)	$	—		$	—		$	—		$	1
Equity in earnings (losses) of investments
TEG and TEP		—			(2	)		3			(4	)
NuStart Energy Development, LLC		(1	)		1			(2	)		(1	)

Total equity in earnings (losses) of investments	$	(1	)	$	(1	)	$	1		$	(5	)

Cash distribution paid to member	$	370		$	157		$	665		$	322


	June 30,		December 31,
	2007		2006

Receivables from affiliates (current)
Exelon(f)	$	—	$	85
ComEd(a)		68		197
PECO(b)		146		153
BSC(c)		—		2

Total receivables from affiliates (current)	$	214	$	437

Contributions to Exelon intercompany money pool(e)	$	—	$	13
Payables to affiliates (current)
Exelon(f)	$	5	$	—
BSC(c)		25		—

Total payables to affiliates (current)	$	30	$	—

Payables to affiliates (noncurrent)
ComEd decommissioning(g)	$	1,856	$	1,760
PECO decommissioning(g)		192		151

Total payables to affiliates (noncurrent)	$	2,048	$	1,911


(a)		Effective January 1, 2007, Generation has a supplier forward agreement with ComEd to provide up to 35% of ComEd’s electricity supply requirements. Prior to 2007, Generation had a PPA with ComEd, which expired December 31, 2006. As a result of the expiration of the PPA with ComEd and the results of the Illinois procurement auctions, Generation is selling more power through bilateral agreements. See Note 13 — Commitments and Contingencies for further detail.

(b)		Generation has a PPA with PECO, as amended, to provide the full energy requirements of PECO through 2010.

(c)		Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. Some third-party reimbursements due to Generation are recovered through BSC.

(d)		Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO. Starting in 2007, Generation purchases only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. In 2006, Generation purchased both electricity and distribution and transmission services from ComEd. Generation’s PPA with ComEd expired December 31, 2006. See Note 13 — Commitments and Contingencies for further detail regarding the PPAs.

(e)		Generation participates in Exelon’s intercompany money pool. Generation earns interest on its contributions to the money pool, and pays interest on its borrowings from the money pool at a market rate of interest.

(f)		In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation. In addition, Generation has a receivable from Exelon for the allocation of certain tax benefits related to a capital loss carryback.

(g)		Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to ComEd and PECO, as applicable, for payment to the customers. See Note 11 — Asset Retirement Obligations for additional information.

ComEd

The financial statements of ComEd include related-party transactions as presented in the tables below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006

Operating revenues from affiliates
Generation(a)	$	—	$	2	$	1	$	3
ComEd Transitional Funding Trust		1		1		2		2
Other		—		—		1		1

Total operating revenues from affiliates	$	1	$	3	$	4	$	6

Purchased power from affiliate
Generation(b)	$	330	$	685	$	710	$	1,456
Operation and maintenance from affiliates
BSC(c)	$	45	$	53	$	95	$	105
Interest expense to affiliates, net
ComEd Transitional Funding Trust(e)	$	7	$	12	$	16	$	26
ComEd Financing II		4		4		7		7
ComEd Financing III		3		3		6		6

Total interest expense to affiliates, net	$	14	$	19	$	29	$	39

Equity in losses of unconsolidated affiliates
ComEd Funding LLC	$	2	$	3	$	4	$	5
Capitalized costs
BSC(c)	$	16	$	19	$	33	$	36
Cash contributions received from parent	$	—	$	—	$	—	$	23


	June 30,			December 31,
	2007			2006

Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	—		$	17
Other		—			1

Total receivables from affiliates (current)	$	—		$	18

Investments in affiliates
ComEd Funding LLC	$	(4	)	$	4
ComEd Financing II		10			10
ComEd Financing III		6			6

Total investments in affiliates	$	12		$	20

Receivable from affiliates (noncurrent)
Generation(d)	$	1,856		$	1,760
ComEd Transitional Funding Trust		15			14
Other		2			—

Total receivable from affiliates (noncurrent)	$	1,873		$	1,774

Payables to affiliates (current)
Generation(b)	$	68		$	197
BSC(c)		18			10
ComEd Financing II		6			6
ComEd Financing III		4			4
Other		—			2

Total payables to affiliates (current)	$	96		$	219

Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust(e)	$	443		$	648
ComEd Financing II		155			155
ComEd Financing III		206			206

Total long-term debt due to financing trusts	$	804		$	1,009


(a)		Starting in 2007, ComEd is delivering electricity to Generation for Generation’s own use at its generation stations. In 2006, ComEd delivered and provided electricity to Generation.

(b)		ComEd’s full-requirements PPA, as amended, with Generation expired December 31, 2006. Starting January 2007, ComEd began procuring electricity from Generation under the supplier forward contract resulting from the reverse-auction procurement process. See Note 5 — Regulatory Issues for more information.

(c)		ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, supply management services, planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)		ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.

(e)		Amount includes a $17 million reallocation from prepaid interest to long-term debt. This reallocation did not have an impact on ComEd’s Consolidated Statement of Operations or ComEd’s Consolidated Statement of Cash Flows.

PECO

The financial statements of PECO include related-party transactions as presented in the tables below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006

Operating revenues from affiliates
Generation(a)	$	2	$	2	$	4	$	4
PETT(b)		1		2		3		4

Total operating revenues from affiliates	$	3	$	4	$	7	$	8

Purchased power from affiliate
Generation(c)	$	497	$	429	$	977	$	845
Operating and maintenance from affiliates
BSC(d)	$	27	$	32	$	55	$	63
Generation		—		—		1		—
Other		—		—		—		1

Total operating and maintenance from affiliates	$	27	$	32	$	56	$	64

Interest expense to affiliates, net
PETT	$	36	$	46	$	75	$	95
PECO Trust III		1		1		3		3
PECO Trust IV		2		2		3		3
Other		1		—		1		—

Total interest expense to affiliates, net	$	40	$	49	$	82	$	101

Equity in losses of unconsolidated affiliates
PETT	$	2	$	2	$	4	$	6
Capitalized costs
BSC(d)	$	6	$	12	$	14	$	29
Cash dividends paid to parent	$	121	$	135	$	276	$	251
Cash contributions received from parent	$	100	$	35	$	165	$	83


	June 30,		December 31,
	2007		2006

Investments in affiliates
PETT	$	51	$	54
PECO Energy Capital Corporation		4		4
PECO Trust IV		6		6

Total investments in affiliates	$	61	$	64

Receivable from affiliate (noncurrent)
Generation decommissioning(e)	$	192	$	151
Borrowings from Exelon intercompany money pool(f)	$	—	$	45
Payables to affiliates (current)
Generation(c)	$	146	$	153
BSC(d)		23		48
Exelon		1		1
PECO Trust III		1		1

Total payables to affiliates (current)	$	171	$	203

Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	2,050	$	2,404
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	2,234	$	2,588

Shareholders’ equity — receivable from parent(g)	$	925	$	1,090


(a)		PECO provides energy to Generation for Generation’s own use primarily at its generation stations.

(b)		PECO receives a monthly service fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

(c)		PECO has entered into a PPA with Generation. See Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for more information regarding the PPA.

(d)		PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, supply management services, planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(e)		PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

(f)		PECO participates in Exelon’s intercompany money pool. PECO earns interest on its contributions to the money pool and pays interest on its borrowings from the money pool at a market rate of interest.

(g)		PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2007 through 2010.


17.	Subsequent Events (Exelon and ComEd)

On July 24, 2007, following extensive discussions with legislative leaders in Illinois, ComEd, Generation, and other utilities and generators in Illinois reached an oral agreement (the Settlement) with various representatives from the State of Illinois concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. The Settlement was recorded in a confirming letter to the Speaker of the Illinois House of Representatives, the President of the Illinois Senate, the minority leaders of the Illinois House and Senate, and the Attorney General of the State of Illinois from ComEd, Generation, and other utilities and generators in Illinois. The Settlement will be effective only upon enactment of Proposed Legislation, which was drafted as part of the Settlement and attached as an exhibit to the Letter. See Note 5 — Regulatory Issues for more information.


Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

(Dollars in millions except per share data, unless otherwise noted)

General

Exelon is a utility services holding company. It operates through subsidiaries in the following operating segments:


	•	Generation, whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.

	•	ComEd, whose business consists of the purchase and regulated retail and wholesale sale of electricity and the provision of distribution and transmission services to retail and wholesale customers in northern Illinois, including the City of Chicago.

	•	PECO, whose businesses consists of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in Pennsylvania in the counties surrounding the City of Philadelphia.

See Note 15 of the Combined Notes to Consolidated Financial Statements for segment information.

Exelon’s corporate operations, which are performed through its business services subsidiary, Exelon Business Services Company (BSC), provide Exelon’s business segments with a variety of support services. The costs of these services are directly charged or allocated to the applicable business segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

EXELON CORPORATION

Executive Overview

Financial Results. Exelon’s net income was $702 million for the three months ended June 30, 2007 as compared to $644 million for the three months ended June 30, 2006 and diluted earnings per average common share were $1.03 for the three months ended June 30, 2007 as compared to $0.95 for the three months ended June 30, 2006.

Exelon’s net income was $1,393 million for the six months ended June 30, 2007 as compared to $1,044 million for the six months ended June 30, 2006 and diluted earnings per average common share were $2.05 for the six months ended June 30, 2007 as compared to $1.55 for the six months ended June 30, 2006.

The increase for both the three and six-month periods ended June 30, 2007 was primarily due to the following:


	•	higher average margins on Generation’s wholesale market sales primarily due to the end of the below-market power purchase agreement (PPA) with ComEd;

	•	favorable weather conditions in the ComEd and PECO service territories;

	•	increased delivery volume, excluding the effects of weather, at ComEd and PECO;

	•	increased transmission revenues at ComEd as a result of the 2007 transmission rate case; and

	•	increased rates for delivery services at ComEd.

In addition to the items listed above, the six-month period ended June 30, 2007 increased due to the following:


	•	a favorable PJM Interconnection, LLC (PJM) billing settlement with PPL Electric (PPL);

	•	increased nuclear output at Generation reflecting fewer outage days; and

	•	decreased nuclear refueling outage costs.

The factors driving the overall increase in net income for the three and six month periods ended June 30, 2007 were partially offset by the following:


	•	unrealized mark-to-market losses on contracts not yet settled;

	•	lower margins (operating revenues less purchased power expense) at ComEd due to the end of the regulatory transition period and associated transition revenues;

	•	the impact of ComEd’s 2007 rate relief program and other post rate freeze period transition expenses;

	•	higher operating and maintenance expenses, primarily associated with an update of the nuclear decommissioning asset retirement obligation recorded in the second quarter of 2006, labor-related inflation, and increased allowance for uncollectible accounts expense;

	•	increased depreciation and amortization expense, primarily related to competitive transition charge (CTC) amortization at PECO; and

	•	the impact of favorable tax settlements at PECO in 2006.

Financing Activities. During the six months ended June 30, 2007, Exelon met its capital resource requirements primarily with internally generated cash as well as funds from external sources, including the capital markets, and through bank borrowings. During March 2007, ComEd and PECO issued $300 million and $175 million, respectively, of First Mortgage Bonds. In addition, during the six months ended June 30, 2007, ComEd borrowed $475 million under its credit facilities and repaid all outstanding commercial paper. During the six months ended June 30, 2007, certain rating agencies downgraded ComEd and PECO’s debt ratings. PECO’s downgrade reflects a change in a rating agency’s short-term and long-term rating linkage practices.

Regulatory and Environmental Developments. The following significant regulatory and environmental developments occurred during 2007. See Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements for further information.


	•	On April 23, 2007, ComEd announced the implementation of a new $64 million rate relief package to be provided to ComEd customers most affected by recent electricity rate increases. The rate relief package is expected to provide benefits to ComEd’s customers of $44 million in 2007 and $10 million per year during 2008 and 2009. Approximately $18 million of credits were issued to customers through June 30, 2007.

On July 24, 2007, ComEd, Generation, and other utilities and generators in Illinois reached an oral agreement (the Settlement) with various representatives from the government of the State of Illinois concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. The Settlement was recorded in a confirming letter (the Letter) to the Speaker of the Illinois House of Representatives, the President of the Illinois Senate, the minority leaders of the Illinois House and Senate, and the Attorney General of the State of Illinois (the Attorney General) from ComEd, Generation, and other utilities and generators in Illinois. The Settlement will be effective only upon enactment of proposed legislation (Proposed Legislation) attached as an exhibit to the Letter.

Under the Settlement and the Proposed Legislation, Illinois electric utilities, their affiliates, and generators of electricity in Illinois would be expected to make voluntary contributions of approximately $1 billion over a period of four years to programs that would provide rate relief to Illinois electricity customers and funding for the new Illinois Power Agency. Generation and ComEd have committed to contributing an aggregate of over $800 million to rate relief programs and funding for the new Illinois Power Agency. ComEd would continue executing upon its $64 million rate relief package announced April 23, 2007. Generation would contribute an aggregate of up to $747 million, of which $435 million would be available to reimburse ComEd for rate relief programs for ComEd customers, and $307.5 million would be available for rate relief programs for customers of other Illinois utilities and $4.5 million would be available for funding for the Illinois Power Agency. ComEd, Generation, and the Illinois Attorney General have also entered into a release and settlement agreement releasing and dismissing with prejudice all litigation, claims and

regulatory proceedings and appeals related to the procurement of power, including ICC and FERC proceedings. In the event that legislation is passed prior to August 1, 2011 that would freeze or reduce electric rates or impose a generation tax on any party to the Settlement, the contributors to the rate relief funds would be allowed to terminate their funding commitments and would be allowed to recover any undisbursed funds set aside for rate relief.

The Proposed Legislation would also establish a new state agency, known as the Illinois Power Agency, which would be authorized to design annual five-year electricity supply portfolio plans for electric utilities and administer a competitive procurement process for utilities to procure the electricity supply resources identified in the supply portfolio plans. Additionally, ComEd and Generation have entered into a five-year financial swap arrangement whereby ComEd will pay fixed prices and Generation will pay a market price for a portion of ComEd’s load. The financial swap arrangement will become effective upon the effective date of the Proposed Legislation. The Proposed Legislation would deem this arrangement prudent and ComEd would receive full recovery of its costs in its rates.

Other provisions in the Proposed Legislation would extend the ability of utilities to engage in divestiture and other restructuring transactions without prior ICC approval and would ensure that until at least June 30, 2022, the state would not prohibit an electric utility from maintaining its membership in a FERC-approved regional transmission organization chosen by the utility. Furthermore, the procurement plans implemented by electric utilities would require inclusion of cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its customers by June 1, 2008, increasing to 10% by June 1, 2015, with a goal of 25% by June 1, 2025. Utilities would be allowed to pass through any costs or savings from the procurement of these renewable resources.


	•	Illinois Procurement Case and Related Proceedings — In January 2007, ComEd began procuring electricity under supplier forward contracts with various suppliers, including Generation. The supplier forward contracts resulted from a “reverse-auction” competitive bidding process, which was approved by the Illinois Commerce Commission (ICC) on January 24, 2006 and permits recovery by ComEd of its electricity procurement costs from retail customers with no markup. The first auction took place in September 2006. The ICC order approving the auction process is under appeal by various parties; the Illinois Attorney General has agreed to dismiss its appeal in connection with the Settlement. Consistent with the process previously approved by the ICC, the ICC has opened a proceeding to consider improvements to the competitive procurement process. It is anticipated that a final order will be entered in that proceeding with sufficient time to incorporate changes into the 2008 procurement process.

	•	Residential Rate Stabilization Program — In January 2007, ComEd launched the rate stabilization program approved by the ICC that allows residential customers the choice to limit the impact of any rate increases over the next three years. The program has an “opt-in” feature that gives customers the choice to participate, which began with the April 2007 billing period. Under the program, residential customers choosing to participate will have their average annual rate increases capped at 10% in 2007, 2008 and 2009. Costs that exceed the cap are deferred and charged to customers over the following three years, 2010 to 2012. A carrying charge at a rate of 3.25% per year is assessed to participants to partially cover ComEd’s cost of financing the program. As of June 30, 2007, approximately 36,000 or 1% of ComEd’s residential customers had enrolled in the program, and ComEd had deferred less than $1 million under this program.

	•	Illinois Rate Design Investigation — On March 2, 2007, the ICC voted to initiate investigations into ComEd’s and the Ameren Corporation (Ameren) utilities’ rate designs, particularly for residential and residential space-heating customers. The ICC has a schedule that contemplates a final order by September 2007, which would allow implementation of changes, if any, prior to the next winter heating season.

	•	Transmission Rate Case — On March 1, 2007, ComEd filed a request with the Federal Energy Regulatory Commission (FERC), seeking approval to increase the rate ComEd receives for transmission services. ComEd also requested incentive rate treatment for certain transmission projects. On June 5, 2007, FERC issued an order that conditionally approves ComEd’s proposal to implement a formula-based transmission rate effective as of May 1, 2007, but subject to refund, hearing procedures and conditions. The FERC order provides that further hearing and settlement procedures be conducted to determine the reasonableness of


		certain elements of ComEd’s formula-based rate. The order denied ComEd’s request for incentive rate treatment on investment in two transmission projects and the inclusion of construction work in progress in rate base. The order directed ComEd to file a revised formula reflecting these findings within 30 days. The new rate will increase an average residential customer bill by about 1% and will result in an annual increase in the transmission revenue requirement of $116 million, although the rate increase is subject to further adjustment and refund depending on the outcome of the settlement and hearing procedures. On July 5, 2007, ComEd filed a request for rehearing, asking FERC to reconsider the denial of incentive rate treatment on the two new transmission projects and the denial of construction work in progress in rate base and certain other elements of the June 5, 2007 order.


	•	PECO AEPS Filing — On March 19, 2007, PECO filed a request with the Pennsylvania Public Utility Commission (PAPUC) for approval to acquire and bank up to 450,000 non-solar Tier I Alternative Energy Credits (equivalent to up to 240 MW of electricity generated by wind) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance under the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act) following the completion of its transition period. On July 16, 2007, the Pennsylvania legislature modified the previously proposed AEPS Act in House Bill (HB) 1203. The modification did not affect PECO’s request for acquiring and banking Alternative Energy Credits or the proposed deferral of related costs.

	•	On May 19, 2006, FERC issued a Notice of Proposed Rule Making (NOPR) on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities. The NOPR proposes a set of regulations that would modify the tests that Generation and other market participants must satisfy to be entitled to market-based rates. On June 21, 2007, FERC issued a Final Rule. Generation is currently evaluating the impact of the Final Rule.

Outlook for 2007 and Beyond.

Exelon’s future financial results will be affected by a number of factors, including the following:


	•	Legislation proposed in the State of Illinois in July 2007 in connection with the Settlement has significantly reduced the probability of rate freeze legislation and other legislative actions proposed in previous periods. The Proposed Legislation contemplated by the Settlement, if enacted, should provide ComEd with greater stability and certainty that it will be able to procure electricity and pass through the costs of that electricity to its customers. The Proposed Legislation would establish a new competitive procurement model developed by the new Illinois Power Agency, by which ComEd would procure its energy supply. ComEd would stabilize a portion of its costs of procurement pursuant to a five-year financial swap arrangement with Generation. ComEd would be allowed to fully recover the costs of procuring energy, including the impacts of the swap agreement, in its rates. In the event that legislation is passed in the Illinois General Assembly prior to August 1, 2011 that freezes or reduces electric rates or imposes a generation tax, ComEd and Generation, as contributors to certain rate relief programs, would be allowed to terminate their funding commitments to such programs and recover any undisbursed funds set aside for rate relief.


	•	PECO was subject to electric rate caps on its transmission and distribution rates through December 31, 2006 and is subject to caps on its generation rates through December 31, 2010. PECO’s transmission and distribution rates will continue in effect until PECO files a rate case or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so. PECO is or will be involved in proceedings involving annual changes in its electric and gas universal service fund cost charges, its electric CTC/intangible transition charge reconciliation mechanism, and its purchased gas cost rate, all of which relate to PECO’s recovery of the applicable costs.

	•	Effective for customer bills for electric generation service delivered after customers’ January 2007 meter readings, and in accordance with its 1998 restructuring settlement with the PAPUC, PECO implemented a scheduled electric generation rate increase that will result in approximately $190 million of additional operating revenues in 2007 as compared to 2006 and a corresponding increase in purchased power, in accordance with PECO’s PPA with Generation, with no resulting impact on pre-tax operating income. The impact of this rate increase on Exelon and Generation will be an increase in operating revenues and pre-tax operating income of approximately $190 million.

	•	Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2007 and 2008. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years as well.

	•	Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term contracts for uranium concentrates, and long term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Non-performance by these counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with these commodity price exposures.

	•	The PPA between Generation and PECO expires at the end of 2010. Current market prices for electricity have increased significantly over the past few years due to the rise in natural gas and other fuel prices. As a result, PECO customers’ generation rates are below current wholesale energy market prices and Generation’s margins on sales in excess of PECO’s requirements have improved historically. Generation’s ability to maintain those margins following the expiration of the PPA will partially depend on future wholesale market prices.

	•	Select northeast and Mid-Atlantic States have developed a model rule, via the Regional Greenhouse Gas Initiative, to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to regulate carbon emissions could occur in the future. If such state regulation and/or legislation become effective, Exelon may incur costs in further limiting the emissions from certain of its fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies. However, Exelon may benefit from stricter emission standards due to its significant nuclear capacity, which is not anticipated to be affected by the proposed emission standards.

	•	Exelon anticipates that it will be subject to the ongoing pressures of rising operating expenses due to increases in costs, such as medical benefits and rising payroll costs due to inflation. Also, Exelon will continue to incur significant capital costs associated with its commitment to produce and deliver energy reliably to its customers. Increasing capital costs may include the price of uranium, which fuels the nuclear facilities, and continued capital investment in Exelon’s aging distribution infrastructure and generating


		facilities. Exelon is determined to operate its businesses responsibly and to appropriately manage its operating and capital costs while serving its customers and producing value for its shareholders.


	•	Exelon pursues growth opportunities that are consistent with its disciplined approach to investing to maximize earnings and cash flows. On September 29, 2006, Generation notified the Nuclear Regulatory Commission (NRC) that Generation will begin the application process for a combined construction and operating license that would allow for the possible construction of a new nuclear plant at an as-yet unnamed location in Texas. The filing of the letter with the NRC launches a process that preserves for Exelon the option to develop a new nuclear plant in Texas without immediately committing to the full project. The decision to build a new nuclear plant has not been made at this time; however on June 28, 2007, Generation announced that it has selected primary and secondary sites, both in southeast Texas, for a federal license application that, if obtained, would allow construction and operation of a new nuclear plant should Generation decide to build one. Among the various conditions that must be resolved before any formal decision to build is made are a permanent solution to spent nuclear fuel disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using new technology can be financially successful. Generation expects to submit the application to the NRC for the combined construction and operating license in 2008.

	•	During 2006, FERC issued its order approving PJM’s settlement proposal related to its Reliability Pricing Model (RPM) to provide for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. FERC’s adoption of the settlement proposal has had a favorable impact for owners of generation facilities, particularly for such facilities located in constrained zones. The first auction took place in April 2007 and resulted in Generation auctioning capacity at prices ranging from $40.80/MW to $197.67/MW per day for the regions in which Generation has capacity for the period from June 1, 2007 through May 31, 2008. The second auction took place in July 2007 and resulted in Generation auctioning capacity at prices ranging from $111.92/MW to $148.80/MW per day for the regions in which Generation has capacity for the period from June 1, 2008 through May 31, 2009. Subsequent auctions will be conducted in October 2007 and January 2008 to auction capacity for periods through May 2011.

	•	On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency (EPA) holding that carbon dioxide and other greenhouse gas (GHG) emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule, and Federal or state legislation.

	•	On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in a challenge to the final Phase II rule implementing Section 316(b) of the Clean Water Act. By its action, the court invalidated compliance measures that the utility industry supported because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. The court’s decision has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. Several industry parties to the litigation sought review by the entire U.S. Court of Appeals for the Second Circuit, which was denied on July 5, 2007. Parties to the litigation have until October 3, 2007 to file a petition seeking review by the U.S. Supreme Court. On July 9, 2007, the EPA formally suspended the Phase II rule due to the uncertainty about the specific compliance requirements created by the court’s remand of significant provisions of the rule. Until the EPA finalizes the rule on remand (which could take up to several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures. Due to this uncertainty, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. If the final rule, or interim state requirements under best professional judgment, have performance standards that require the reduction of cooling water


		intake flow at the plants consistent with closed loop cooling systems, then the impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, financial position and cash flows could be material.


	•	On May 10, 2007, after completion of a two year rule making process, the PAPUC adopted final Default Supplier (Provider of Last Resort) regulations, an accompanying policy statement, and a price mitigation policy statement. The regulations allow for competitive procurement by distribution companies through auctions or Requests for Proposals, with full cost recovery and no retrospective prudence review. According to the policy statement, the PAPUC expects companies to procure power, on a customer-class basis, using contracts of varying expiration dates, and prefers contracts with a duration of one year or less, except for contracts for compliance with the AEPS Act. The PAPUC also expects companies to reconcile costs and adjust rates at least quarterly for most customers, but hourly or monthly for larger energy users. The PAPUC believes this combination will stimulate competition, send market-price signals and avoid price spikes following long periods of fixed, capped rates. The PAPUC also ordered the elimination of (1) declining-block rates, while allowing rates to be phased out if the resulting rate increase is greater than 25%; and (2) demand charges for large customers, while entertaining requests to retain those charges on a case-by-case basis. Default service providers such as PECO will be required to make their implementation filings a minimum of 12 months prior to the end of the generation rate cap period, which for PECO, expires December 31, 2010. The final Default Service Regulations adopted by the PAPUC will become effective once approved by Pennsylvania’s Independent Regulatory Review Commission (such approval being received on July 19, 2007), and after subsequent review by the Pennsylvania Office of Attorney General, the Pennsylvania Governor’s Budget Office and the standing committees of both houses of the Pennsylvania General Assembly. Once that review and approval process is completed, the regulations would become final once published in the Pennsylvania Bulletin.

	•	In Pennsylvania and other states where transition periods have ended or rate caps have expired, there is growing pressure from state regulators and politicians to mitigate the potential impact of generation price increases on retail customers. The experiences in other states following the end of a regulatory transition period has led to a heightened state of political concern that significant generation price increases also will occur after the expiration of rate caps in Pennsylvania. While PECO’s regulatory transition period does not end until December 31, 2010, these transition periods have ended for six Pennsylvania electric distribution companies and, in some instances, generations price increases have ensued. Partly in response to the rate increases and as part of his environmental agenda, Pennsylvania Governor Edward Rendell announced an Energy Independence Strategy earlier this year that included a package of proposed legislation. Provisions of that legislation would, among other things, require default suppliers such as PECO to procure electricity for their default-service customers, after the end of their electric restructuring period (post-2010 for PECO), through a least-cost portfolio approach, with preferences for conservation and renewable power. The legislation also would require installation of metering technology to provide time-of-use rates to retail customers, provide for a phase-in of increased generation rates after expiration of rate caps, permit distribution companies to enter into long-term contracts with large industrial customers, and create a fee on electric consumption that the state would direct toward conservation and renewable technologies. On July 18, 2007, Governor Rendell signed into law HB1203, amending the AEPS Act (amending the force majeure and solar provisions), and HB1530, which amends Title 66 of the Pennsylvania Utility Code, allowing electric distribution companies to negotiate special contracts for larger customers. Other elements of the Governor’s proposed energy package will be considered further at a special legislative session to be held beginning September 17, 2007.

	•	Prior to June 30, 2007, the Illinois House and Senate passed Senate Bill (SB) 1544 which provides for market based sourcing of generation and the sale of electricity for Illinois tax purposes. SB1544 is currently awaiting signature by the Governor of Illinois to become law. The Governor of Illinois has 60 days from June 29, 2007 to act on SB1544 before such legislation automatically becomes law. If enacted, the legislation becomes effective January 1, 2008. Exelon and Generation are currently assessing the impact SB1544 may have on their results of operations or cash flows.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 2006 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for asset retirement obligations, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement welfare benefits, regulatory accounting, derivative instruments, contingencies, severance and revenue recognition.

Taxation

The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate their obligations to taxing authorities. Beginning January 1, 2007, the Registrants began accounting for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48). If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. Prior to January 1, 2007, the Registrants estimated their uncertain income tax obligations in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5) and Statement of Financial Accounting Concepts No. 6, “Elements of Financial Statements — a replacement of FASB Concepts Statement No. 3 (incorporating an amendment of FASB Concepts Statement No. 2)” (CON 6). The Registrants also have non-income tax obligations related to real estate, sales and use and employment-related taxes and ongoing appeals related to these tax matters that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and CON 6.

Accounting for tax obligations requires judgments, including estimating reserves for potential adverse outcomes regarding tax positions that have been taken. The Registrants also assess their ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. The Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. While the Registrants believe the resulting tax reserve balances as of June 30, 2007 and December 31, 2006 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and CON 6 as applicable, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.

New Accounting Pronouncements

See Note 3 of the Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements.

Results of Operations — Exelon Corporation

Three Months Ended June 30, 2007 Compared To Three Months Ended June 30, 2006


	Three Months
	Ended						Favorable
	June 30,						(Unfavorable)
Exelon Corporation	2007			2006			Variance

Operating revenues	$	4,501		$	3,697		$	804
Operating expenses
Purchased power and fuel expense		1,640			1,073			(567	)
Operating and maintenance expense		1,062			881			(181	)
Depreciation and amortization		369			371			2
Taxes other than income		199			170			(29	)

Total operating expenses		3,270			2,495			(775	)

Operating income		1,231			1,202			29

Other income and deductions
Interest expense		(161	)		(154	)		(7	)
Interest expense to affiliates, net		(53	)		(68	)		15
Equity in losses of unconsolidated affiliates and investments		(43	)		(22	)		(21	)
Other, net		43			46			(3	)

Total other income and deductions		(214	)		(198	)		(16	)

Income from continuing operations before income taxes		1,017			1,004			13
Income taxes		314			363			49

Income from continuing operations		703			641			62
Income (loss) from discontinued operations, net of income taxes		(1	)		3			(4	)

Net income	$	702		$	644		$	58

Diluted earnings per share	$	1.03		$	0.95		$	0.08

Net Income. Exelon’s net income for the three months ended June 30, 2007 reflects higher average margins on wholesale market sales; favorable weather conditions in the ComEd and PECO service territories; increased electric and gas deliveries, excluding the effects of weather, at ComEd and PECO; increased pricing for delivery services at ComEd and PECO; and increased transmission revenues at ComEd. These increases were partially offset by unrealized mark-to-market losses on contracts not yet settled; decreased energy margins at ComEd; higher operating and maintenance expenses, including higher nuclear refueling outage expenses, labor-related inflation and increased allowance for uncollectible accounts expense at ComEd; the impact of ComEd’s 2007 rate relief program and other post rate freeze period transition expenses; an update of the nuclear decommissioning asset retirement obligation recorded in the second quarter of 2006; and favorable tax settlements at PECO in 2006.

Operating Revenues. Operating revenues increased due to an increase in wholesale and retail electric sales at Generation due to higher volumes of generation sold to the market as a result of the expiration of the ComEd PPA in 2006; higher market prices; favorable weather conditions in the ComEd and PECO service territories; higher electric and gas delivery volumes, excluding the effects of weather and customer choice, at ComEd and PECO; rate changes and mix at ComEd due to the end of the rate freeze and implementation of market-based rates for electricity; impact of the distribution rate increase; and increased transmission revenues at ComEd resulting from the 2007 transmission rate case. These increases were partially offset by ComEd customers switching to competitive electric generation suppliers and the impact of ComEd’s 2007 rate relief program. See further analysis and discussion of operating revenues by segment below.

100

Purchased Power and Fuel Expense. Purchased power and fuel expense increased due to higher volumes of power purchased in the market and higher market energy prices. Purchased power represented 19% of Generation’s total supply for the three months ended June 30, 2007 and compared to 17% for the three months ended June 30, 2006. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to the impact of higher nuclear refueling outage costs; labor-related inflation; the impact of ComEd’s 2007 rate relief program and other post rate freeze period transition expenses; increased allowance for uncollectible accounts expense at ComEd; and a decrease in Generation’s nuclear decommissioning obligation related to the AmerGen nuclear plants recorded in the second quarter of 2006. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased primarily due to lower amortization related to investments in synthetic fuel-producing facilities. This decrease was partially offset by additional CTC amortization at PECO.

Taxes Other Than Income. Taxes other than income increased due to favorable tax settlements in 2006 and higher taxes on utility revenues at PECO in 2007.

Other Income and Deductions. The change in other income and deductions reflects reduced earnings associated with investments in synthetic fuel-producing facilities and expenses recorded in 2006 related to the now terminated merger with Public Service Enterprise Group Incorporated (PSEG).

Effective Income Tax Rate. The effective income tax rate from continuing operations was 30.9% for the three months ended June 30, 2007 compared to 36.2% for the three months ended June 30, 2006. The synthetic-fuel producing facilities credit decreased the effective income tax rate from continuing operations by 6.5% for the three months ended June 30, 2007. Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc. (Sithe). In addition, Exelon has sold or wound down substantially all components of Enterprises. Accordingly, the results of operations and any gain or loss on the sale of these entities have been presented as discontinued operations within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations and Comprehensive Income. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the three months ended June 30, 2007 compared to the same period in 2006 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Income (Loss) from Continuing Operations by Business Segment


	Three Months Ended					Favorable
	June 30,					(Unfavorable)
	2007		2006			Variance

Generation	$	578	$	497		$	81
ComEd		29		127			(98	)
PECO		96		93			3
Other(a)		—		(76	)		76

Total	$	703	$	641		$	62


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

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Net Income (Loss) by Business Segment


	Three Months Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Generation	$	578		$	500		$	78
ComEd		29			127			(98	)
PECO		96			93			3
Other(a)		(1	)		(76	)		75

Total	$	702		$	644		$	58


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

Results of Operations — Generation


	Three Months Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	2,641		$	2,214		$	427
Operating expenses
Purchased power and fuel		974			843			(131	)
Operating and maintenance		618			440			(178	)
Depreciation and amortization		65			72			7
Taxes other than income		47			41			(6	)

Total operating expenses		1,704			1,396			(308	)

Operating income		937			818			119

Other income and deductions
Interest expense		(31	)		(40	)		9
Equity in losses of investments		(1	)		(1	)		—
Other, net		22			14			8

Total other income and deductions		(10	)		(27	)		17

Income from continuing operations before income taxes		927			791			136
Income taxes		349			294			(55	)

Income from continuing operations		578			497			81
Income from discontinued operations, net of income taxes		—			3			(3	)

Net income	$	578		$	500		$	78

Net Income. Second quarter 2007 net income was $578 million compared with $500 million in the second quarter of 2006. Generation’s net income in the second quarter of 2007 increased compared with the same quarter last year primarily due to higher revenue, net of purchased power and fuel expense, offset by increased operating and maintenance expense, primarily associated with an update of the nuclear decommissioning asset retirement obligation recorded in the second quarter of 2006, higher nuclear refueling outage expenses, and wage-related inflation. Generation’s revenue, net of purchased power and fuel expense, increased by $296 million in the second quarter of 2007 compared with the second quarter of 2006, which was driven by higher average margins primarily due to the end of the below-market price PPA with ComEd at the end of 2006, the contractual increase in the prices associated with Generation’s PPA with PECO, and partially offset by lower nuclear generation due to a higher number of refueling outage days.

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Operating Revenues. For the three months ended June 30, 2007 and 2006, Generation’s sales were as follows:


	Three Months
	Ended
	June 30,
Revenue	2007		2006		Variance			% Change

Electric sales to affiliates	$	828	$	1,098	$	(270	)		(24.6	)%
Wholesale and retail electric sales		1,680		943		737			78.1	%

Total electric sales revenue		2,508		2,041		467			22.9	%
Retail gas sales		87		91		(4	)		(4.4	)%
Trading portfolio		32		3		29			n.m.
Other operating revenue(a)		14		79		(65	)		(82.3	)%

Total operating revenue	$	2,641	$	2,214	$	427			19.3	%


(a)		Includes sales relating to fossil fuel sales, operating service agreements and decommissioning revenue from PECO in 2007 and tolling agreements, fossil fuel sales, operating service agreements and decommissioning revenue from ComEd and PECO in 2006.

n.m. Not meaningful


	Three Months
	Ended
	June 30,
Sales (in GWhs)	2007		2006		Variance			% Change

Electric sales to affiliates		14,878		27,947		(13,069	)		(46.8	)%
Wholesale and retail electric sales		30,911		18,744		12,167			64.9	%

Total electric sales		45,789		46,691		(902	)		(1.9	)%

Trading volumes of 4,775 GWhs and 7,769 GWhs for the three months ended June 30, 2007 and 2006 respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $270 million for the three months ended June 30, 2007, as compared to the same period in 2006. The decrease was primarily due to a $464 million decrease from lower electric sales volume, partially offset by higher prices resulting in a $194 million increase in revenues.

In the ComEd territories, lower volumes resulted in a $485 million decrease in revenues, partially offset by a $146 million increase in revenues due to higher prices. Generation’s PPA with ComEd expired December 31, 2006. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation is selling more power through bilateral agreements, which resulted in higher prices, but a decrease in volumes to ComEd.

In the PECO territories, higher prices resulted in increased revenues of $48 million due to a scheduled electric generation rate increase that took effect January 1, 2007. Additionally, volumes increased resulting in increased revenues of $21 million.

Wholesale and retail electric sales. The increase in Generation’s wholesale and retail electric sales for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Volume	$	615
Price		122

Increase in wholesale and retail electric sales	$	737

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Wholesale and retail electric sales increased $737 million for the three months ended June 30, 2007 as compared to the same period in 2006. The increase was the result of higher volumes of generation sold to the market at higher prices as a result of the expiration of the ComEd PPA in 2006.

Retail gas sales. Retail gas sales decreased $4 million for the three months ended June 30, 2007 as compared to the same period in 2006, of which $8 million was due to lower volumes as a result of lower demand, offset by a $4 million increase due to higher realized prices.

Other revenue. The decrease in other revenues for the three months ended June 30, 2007 compared to the same period in 2006 was due to a $16 million decrease related to the termination of decommissioning collections from ComEd in accordance with the terms and conditions of the ICC Order which only permitted such collections through December 31, 2006. There was a decrease of $36 million due to the cessation of a tolling agreement. Additionally, a $13 million decrease in other revenues was attributable to the sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP) on February 9, 2007 and the resulting absence of revenue thereafter.

Purchased Power and Fuel Expense. Generation’s supply sources are summarized below:


	Three Months
	Ended
	June 30,
Supply Source (in GWhs)	2007		2006		Variance			% Change

Nuclear generation(a)		34,350		35,442		(1,092	)		(3.1	)%
Purchases — economic hedge portfolio		8,580		8,101		479			5.9	%
Fossil and hydroelectric generation		2,859		3,148		(289	)		(9.2	)%

Total supply		45,789		46,691		(902	)		1.9	%


(a)		Represents Generation’s proportionate share of the output of its nuclear generating plants, including Salem, which is operated by PSEG Nuclear, LLC.

The changes in Generation’s purchased power and fuel expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


							Increase
	Price			Volume			(Decrease)

Purchased power costs	$	30		$	56		$	86
Generation cost		(23	)		(9	)		(32	)
Fuel resale cost		5			(8	)		(3	)
Mark-to-market		n.m.			n.m.			80

Increase in purchased power and fuel expense							$	131

n.m. Not meaningful

Purchased Power Cost. Purchased power cost includes all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation had higher purchased power volumes primarily due to lower nuclear output, partially offset by lower purchased power volumes needed to supply ComEd due to the expiration of the PPA at December 31, 2006. Additionally, Generation realized overall higher prices for purchased power. See Note 13 of the Combined Notes to Consolidated Financial Statements.

Generation Cost. Generation cost includes fuel cost for internally generated energy. Generation experienced overall lower generation costs for the three months ended June 30, 2007 as compared to the same period in 2006 due to decreased prices related to fossil fuel generation. The decreased volume of $9 million was primarily due to lower nuclear and fossil fuel generation.

Fuel Resale Cost. Fuel resale cost includes retail gas purchases and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs for the three months ended June 30, 2007 as compared to quarter ended

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2006 consisted of overall higher prices resulting in an increase of $5 million. Additionally, a decrease of $8 million was the result of lower volumes caused by lower demand.

Mark-to-market. Mark-to-market gains on power hedging activities were $16 million for the three months ended June 30, 2007 compared to gains of $50 million for the same period in 2006. Mark-to-market losses on fuel hedging activities were $38 million for the three months ended June 30, 2007 compared to gains of $8 million for the same period in 2006.

Generation’s average margins per MWh of electricity sold during the three months ended June 30, 2007 and 2006 were as follows:


	Three Months Ended
	June 30,
($/MWh)	2007		2006		% Change

Average electric revenue
Electric sales to affiliates	$	55.65	$	39.29		41.6	%
Wholesale and retail electric sales		54.35		50.31		8.0	%
Total — excluding the trading portfolio		54.77		43.71		25.3	%
Average electric supply cost(a) — excluding the trading portfolio		19.27		16.04		20.1	%
Average margin — excluding the trading portfolio		35.50		27.67		28.3	%


(a)		Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales and other sales.

Nuclear fleet operating data for the three months ended June 30, 2007 and 2006 were as follows:


	Three Months
	Ended
	June 30,
	2007			2006

Nuclear fleet capacity factor(a)		93.6	%		95.5	%
Nuclear fleet production cost per MWh(a)	$	14.29		$	12.94


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor decreased primarily due to more planned refueling outage days during the three months ended June 30, 2007 compared to the same period in 2006. This increase in planned refueling outage days was partially offset by a decrease in non-refueling outage days. For the three months ended June 30, 2007 and 2006, refueling outage days totaled 55 and 35, respectively, while non-refueling outage days totaled 18 and 24, respectively. The lower number of net MWh’s generated due to the higher number of planned refueling outage days along with the associated refueling outage costs, resulted in a higher production cost per MWh for the three months ended June 30, 2007 as compared to the same period in 2006.

Operating and Maintenance Expense. The increase in operating and maintenance expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Decommissioning-related activities	$	133
Nuclear refueling outage costs		19
Pension, payroll and benefit costs		19
Other		7

Increase in operating and maintenance expense	$	178


	•	The $133 million increase in the nuclear decommissioning-related activities was associated with the recognition of a credit totaling $149 million which represented the reduction in the asset retirement

105


		obligation in excess of the asset retirement cost balance for the AmerGen units recorded in the same period in 2006, offset by a $16 million decrease resulting from the termination of revenue collections from ComEd, which likewise no longer required an offset through operating and maintenance expense.


	•	The $19 million increase in nuclear fueling outage costs was associated with more planned refueling outage days during the three months ended June 30, 2007 as compared to the same period 2006.

	•	The $19 million increase in pension, payroll and benefit costs reflected the impact of inflation as well as an increase in various direct and allocated fringe costs.

	•	The $7 million increase in other operating and maintenance expenses for the three months ended June 30, 2007 compared to the same period in 2006 was primarily due to an increase in contracting charges resulting from increased outage costs for fossil and hydroelectric facilities, offset primarily by a decrease in service agreement-related expenses.

Depreciation and Amortization. The decrease in depreciation and amortization expense for the three months ended June 30, 2007 compared to the same period in 2006 was primarily due to the reassessment of the useful lives, for accounting purposes, of several fossil facilities.

Interest Expense. The decrease in net interest expense for the three months ended June 30, 2007 as compared to the same period in 2006 was primarily attributable to a decline in the amount of commercial paper that was outstanding during the three months ended June 30, 2007 as compared to the same period in 2006.

Other, Net. The change in other, net reflects a gain on sale of investments recognized in the second quarter of 2007.

Effective Income Tax Rate. There was not a significant change in the effective income tax rate for the three months ended June 30, 2007 compared to the same period in 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc (Sithe). Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Operations and Comprehensive Income.

For the three months ended June 30, 2007, there was no significant activity related to discontinued operations included in Generation’s Consolidated Statement of Income and Comprehensive Income. For the three months ended June 30, 2006, Generation’s Consolidated Statement of Income and Comprehensive Income included $3 million (after-tax) gain on disposal of discontinued operations. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

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Results of Operations — ComEd


	Three Months Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	1,420		$	1,453		$	(33	)
Operating expenses
Purchased power		838			766			(72	)
Operating and maintenance		266			218			(48	)
Depreciation and amortization		109			106			(3	)
Taxes other than income		76			71			(5	)

Total operating expenses		1,289			1,161			(128	)

Operating income		131			292			(161	)

Other income and deductions
Interest expense, net		(87	)		(77	)		(10	)
Equity in losses of unconsolidated affiliates		(2	)		(3	)		1
Other, net		5			1			4

Total other income and deductions		(84	)		(79	)		(5	)

Income before income taxes		47			213			(166	)
Income taxes		18			86			68

Net income	$	29		$	127		$	(98	)

Net Income. As more fully described below, ComEd’s net income for the three months ended June 30, 2007 compared to the same period in 2006 reflected lower operating revenues, higher purchased power expense, higher operating and maintenance expense and higher interest expense. Beginning in 2007, ComEd ceased earning margin on the energy component of its deliveries to its customers, nor is it collecting CTC revenues. While ComEd’s 2007 results reflect an $83 million annual rate increase as allowed by the ICC, this rate increase was based generally on 2004 costs and does not include the impacts of increased operating expenses since 2004 or additional net capital investment since the end of 2005. ComEd anticipates filing a new delivery service rate case during the third quarter of 2007 based on a 2006 test year and also filed a transmission rate case during the first quarter 2007. On June 5, 2007, FERC issued an order for the transmission rate case conditionally approving ComEd’s proposal to implement a formula based transmission rate effective May 1, 2007, subject to refund. The requested rate increase is designed to reduce the regulatory lag related to recovery of these costs and returns on ComEd’s investments. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion. In 2007, ComEd incurred increased costs associated with transitioning from the rate freeze period including implementing the Rate Relief and Rate Stabilization programs.

107

Operating Revenues and Purchased Power Expense. The changes in operating revenues and purchased power expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase (Decrease)
	Operating			Purchased			Revenue Net of
	Revenues			Power			Purchased Power

Customer choice	$	(311	)	$	(228	)	$	(83	)
Rate changes and mix		217			273			(56	)
Rate Relief Program		(18	)		—			(18	)
Transmission		26			—			26
Weather		57			34			23
Volume		4			—			4
Other		(8	)		(7	)		(1	)

Total increase (decrease)	$	(33	)	$	72		$	(105	)

Customer choice

Revenue. All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied electricity and generation service. As of June 30, 2007, two competitive electric generation suppliers had been granted approval to serve residential customers in the ComEd service territory. However, they are not currently supplying electricity to any residential customers.

As a result of ComEd’s higher electricity rates, more non-residential customers have elected to have a competitive electric generation supplier provide their electricity. For the three months ended June 30, 2007 and 2006, 51% and 24%, respectively, of electricity delivered to ComEd’s retail customers was provided by competitive electric generation suppliers. Most of the customers previously receiving electricity under the power purchase option (PPO) are now electing either to buy their electricity from a competitive electric generation supplier or from ComEd under tariff rates.


	Three Months
	Ended June 30,
	2007			2006

Retail customers purchasing electricity from a competitive electric generation supplier:
Volume (GWhs)(a)		11,290			5,063
Percentage of total retail deliveries		51	%		24	%
Retail customers purchasing electricity from a competitive electric generation supplier or the ComEd PPO:
Number of customers at period end		41,500			16,100
Percentage of total retail customers		1	%		(b	)
Volume (GWhs)(a)		11,291			6,552
Percentage of total retail deliveries		51	%		31	%


(a)		One GWh is the equivalent of one million kilowatthours (kWh).

(b)		Less than one percent.

Purchased Power. The decrease in purchased power expense from customer choice was primarily due to more ComEd non-residential customers electing to purchase electricity from a competitive electric generation supplier.

108

Rate changes and mix

Revenue. The increase in revenue related to rate changes and mix primarily reflects the end of the rate freeze and the implementation of market-based rates for electricity and the impact of the distribution rate increase. In 2006, most customers were charged a bundled rate that included distribution, transmission and the cost of electricity. Additionally, under Illinois law, no CTCs are permitted to be collected after 2006. As of January 2007, ComEd began billing customers on an unbundled basis which includes separate charges for distribution, transmission and electricity. Given the relatively small increase approved by the ICC in the annual distribution rates of $83 million, the majority of the change in year over year pricing is driven by the inclusion of market-based electricity rates. The market-based electricity rates were determined through the reverse-auction competitive bidding process. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information. Additionally starting in 2007, ComEd is recovering former manufacturing gas plant remediation costs from customers.

Purchased Power. Purchased power increased due to higher electricity prices. The PPA with Generation terminated at the end of 2006. In 2007, as a result of the ICC approved reverse-auction process, ComEd began procuring electricity, including ancillary services, under its supplier forward contracts for the blended and annual products and from PJM-administered wholesale electricity markets for the hourly product. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the reverse-auction process.

Rate Relief Program

Revenue. As part of its program for customer rate relief, ComEd is issuing credits to certain customers. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the Rate Relief Programs.

Transmission

Revenue. In 2007, ComEd experienced increased revenue for the provision of transmission services resulting from increased peak and kWh load within the ComEd service territory. Additionally on June 5, 2007, FERC issued an order for the transmission rate case conditionally approving ComEd’s proposal to implement a formula based transmission rate effective May 1, 2007, subject to refund. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the Transmission Rate Case.

Weather

Revenue. Revenues were higher due to favorable weather conditions for the three months ended June 30, 2007 compared to the same period in 2006. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. In ComEd’s service territory, cooling degree days were 43% higher during the three months ended June 30, 2007 compared to the same period in 2006.

Purchased Power. The increase in purchased power expense attributable to weather was due to higher demand resulting from favorable weather conditions in the ComEd service territory relative to the prior year.

Volume

Revenue. The increase in revenues for the provision of distribution services primarily resulted from an increase in deliveries, excluding the effects of weather, due to an increased number of customers.

Other

Revenue — Economic Hedge Derivative Contracts. During the three months ended June 30, 2007 as compared to the three months ended June 30, 2006, ComEd had a net $5 million decrease in economic hedge derivative contracts activity, including mark-to-market adjustments and settlements.

109

Revenue — Wholesale Contracts. ComEd’s revenues decreased $11 million as a result of certain wholesale contracts expiring in May 2007.

Purchased Power — Wholesale Contracts. ComEd’s purchased power decreased $8 million as a result of certain wholesale contracts expiring in May 2007.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase

Post rate freeze period transition expenses(a)	$	17
Allowance for uncollectible accounts expense(b)		12
Contracting		5
Fringe benefits(c)		5
Wages and salaries		4
Other		5

Increase in operating and maintenance expense	$	48


(a)		Includes increased advertising costs, costs associated with the Rate Relief and Customers’ Affordable Reliable Energy (CARE) programs of $7 million, costs associated with implementing ComEd’s Rate Stabilization plan and other costs associated with transitioning to the post rate freeze period. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information.

(b)		Reflects higher revenues due to increased customer receivables resulting from the inclusion of market-based electricity rates and higher delivery rates. Also reflects an increase in older outstanding receivable balances from customers as a result of a management decision to reduce the number of non-paying customers being disconnected.

(c)		Reflects increases in various fringe benefits primarily due to increased pension and other postretirement benefits costs of $5 million.


	Increase
	(Decrease)

Depreciation expense associated with higher plant balances	$	5
Amortization of regulatory assets		(2	)

Increase in depreciation and amortization expense	$	3

In 2007, ComEd’s amortization reflects the impacts of the elimination of the regulatory asset for recoverable transition costs partially offset by the initial amortization of the various regulatory assets authorized by the ICC in its 2006 orders. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information.

Taxes Other Than Income. Taxes other than income increased for the three months ended June 30, 2007 compared to the same period in 2006 as a result of an increase in real estate and property taxes.

Interest Expense, Net. The increase in interest expense, net for the three months ended June 30, 2007 compared to the same period in 2006 primarily resulted from higher debt balances and higher interest rates. Also in 2007, ComEd’s interest expense, net reflected $3 million of the initial amortization of the regulatory asset related to the early debt retirement costs authorized by the ICC in 2006.

110

Other, Net. Other, net increased for the three months ended June 30, 2007 compared to the same period in 2006. The changes consisted of the following:


	Increase

Gain on disposal of assets and investments, net	$	3
Allowance for funds used during construction, equity		1

Increase in other, net	$	4

Income Taxes. The effective income tax rate was 38.3% for the three months ended June 30, 2007 compared to 40.4% for the three months ended June 30, 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

ComEd Electric Operating Statistics and Revenue Detail


	Three Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2007		2006		Variance			% Change

Full service(a)
Residential		6,359		6,124		235			3.8	%
Small commercial & industrial		3,835		5,709		(1,874	)		(32.8	)%
Large commercial & industrial		539		2,430		(1,891	)		(77.8	)%
Public authorities & electric railroads		213		514		(301	)		(58.6	)%

Total full service		10,946		14,777		(3,831	)		(25.9	)%

PPO
Small commercial & industrial		—		814		(814	)		(100.0	)%
Large commercial & industrial		1		675		(674	)		(99.9	)%

		1		1,489		(1,488	)		(99.9	)%

Delivery only(b)
Small commercial & industrial		4,390		1,291		3,099			n.m.
Large commercial & industrial		6,785		3,772		3,013			79.9	%
Public authorities & electric railroads		115		—		115			n.m.

		11,290		5,063		6,227			123.0	%

Total PPO and delivery only		11,291		6,552		4,739			72.3	%

Total retail deliveries		22,237		21,329		908			4.3	%


(a)		Full service reflects deliveries to customers taking electric service under tariff rates.

(b)		Delivery only service reflects customers electing to receive electricity from a competitive electric generation supplier.

n.m. Not meaningful.

111


	Three Months
	Ended
	June 30,
Electric Revenue	2007			2006		Variance			% Change

Full service(a)
Residential	$	696		$	547	$	149			27.2	%
Small commercial & industrial		380			452		(72	)		(15.9	)%
Large commercial & industrial		35			130		(95	)		(73.1	)%
Public authorities & electric railroads		18			32		(14	)		(43.8	)%

Total full service		1,129			1,161		(32	)		(2.8	)%

PPO(b)
Small commercial & industrial		—			61		(61	)		(100.0	)%
Large commercial & industrial		—			42		(42	)		(100.0	)%

		—			103		(103	)		(100.0	)%

Delivery only(c)
Small commercial & industrial		70			21		49			n.m.
Large commercial & industrial		71			40		31			77.5	%
Public authorities & electric railroads		1			—		1			n.m.

		142			61		81			132.8	%

Total PPO and delivery only		142			164		(22	)		(13.4	)%

Total electric retail revenues		1,271			1,325		(54	)		(4.1	)%
Other revenue(d)		151			125		26			20.8	%
Economic hedge derivative contracts		(2	)		3		(5	)		(166.7	)%

Total operating revenues	$	1,420		$	1,453	$	(33	)		(2.3	)%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariff rates, which include the cost of electricity and the cost of transmission and distribution of the electricity.

(b)		Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC through December 31, 2006.

(c)		Delivery only revenues reflect revenue under tariff rates from customers electing to receive electricity from a competitive electric generation supplier, which includes a distribution charge and a CTC through December 31, 2006.

(d)		Other revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

n.m. Not meaningful.

112

Results of Operations — PECO


	Three Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	1,269		$	1,148		$	121
Operating expenses
Purchased power and fuel		655			577			(78	)
Operating and maintenance		146			141			(5	)
Depreciation and amortization		185			172			(13	)
Taxes other than income		71			53			(18	)

Total operating expenses		1,057			943			(114	)

Operating income		212			205			7

Other income and deductions
Interest expense, net		(64	)		(67	)		3
Equity in losses of unconsolidated affiliates		(2	)		(2	)		—
Other, net		5			2			3

Total other income and deductions		(61	)		(67	)		6

Income before income taxes		151			138			13
Income taxes		55			45			(10	)

Net income		96			93			3
Preferred stock dividends		1			1			—

Net income on common stock	$	95		$	92		$	3

Net Income. PECO’s net income for the three months ended June 30, 2007 compared to the same period in 2006 increased primarily due to higher operating revenues, net of purchased power and fuel expense, which reflected increased sales from favorable weather conditions for electric and gas and increased usage across all customer classes for electric. Partially offsetting higher operating revenues, net of purchased power and fuel expense, was higher CTC amortization, which was in accordance with PECO’s 1998 restructuring settlement with the PAPUC, which was mandated by the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act).

Electric and Gas Operating Revenues, Purchased Power and Fuel Expense. The changes in PECO’s operating revenues and purchased power and fuel expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase (Decrease)
	Electric									Gas									Total
																						Purchased
	Operating			Purchased						Operating			Fuel						Operating			Power and
	Revenues			Power			Net			Revenues			Expense			Net			Revenues			Fuel			Net

Weather	$	29		$	12		$	17		$	26		$	21		$	5		$	55		$	33		$	22
Volume		29			12			17			4			4			—			33			16			17
Rate increases (decreases)		44			44			—			(16	)		(16	)		—			28			28			—
Customer choice		2			2			—			—			—			—			2			2			—
Other rate changes and mix		(3	)		3			(6	)		(2	)		1			(3	)		(5	)		4			(9	)
Other		6			(5	)		11			2			—			2			8			(5	)		13

Total increase	$	107		$	68		$	39		$	14		$	10		$	4		$	121		$	78		$	43

113

Weather

Revenues. The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity and gas. Conversely, mild weather reduces demand. Revenues were higher due to favorable weather conditions in PECO’s service territory, where heating degree days and cooling degree days were 51% and 22% higher, respectively, during the three months ended June 30, 2007 compared to the same period in 2006.

Purchased Power and Fuel Expense. The increase in purchased power and fuel expense attributable to weather was due to higher demand as a result of favorable weather conditions in the PECO service territory relative to the prior year.

Volume

Revenues. The increase in revenues as a result of higher delivery volume, exclusive of the effects of weather and customer choice, reflected increased usage across all customer classes for electric and across residential and large commercial and industrial customer classes for gas. In addition, there was a favorable impact of an increased number of customers primarily in the residential and small commercial and industrial customer classes for electric and gas.

Purchased Power and Fuel Expense. The increase in purchased power and fuel expense as a result of higher delivery volume, exclusive of the effects of weather and customer choice, reflected increased usage across all customer classes for electric and across residential and large commercial and industrial classes for gas. In addition, the increase reflected the impact of an increased number of customers primarily in the residential and small commercial and industrial customer classes for electric and gas.

Rate increases (decreases)

Revenues. The increase in electric revenues attributable to electric rate increases reflects a scheduled electric generation rate increase effective for customer bills for electric generation service delivered after customers’ January 2007 meter readings, which represents the last scheduled rate increase through 2010 under PECO’s 1998 restructuring settlement. This rate increase does not affect operating income as PECO incurs corresponding and offsetting purchased power expense under its PPA with Generation. The decrease in gas revenues was due to net decreases in rates through PAPUC-approved quarterly changes to the purchased gas adjustment clause. The average purchased gas cost rate per million cubic feet in effect for the three months ended June 30, 2007 was 16% lower than the average rate for the same period in 2006.

Purchased Power and Fuel Expense. The increase in purchased power expense attributable to electric rate increases reflects the scheduled generation rate increase under the PPA with Generation. The decrease in fuel expense reflects lower gas prices.

Customer choice

Revenues and Purchased Power. For the three months ended June 30, 2007 and 2006, 2% of energy delivered to PECO’s retail customers was provided by competitive electric generation suppliers.

All PECO customers have the choice to purchase energy from a competitive electric generation supplier. This choice does not affect the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. PECO’s operating income is not affected by customer choice since any increase or decrease in revenues is completely offset by any related increase or decrease in purchased power expense.

114


	Three Months Ended June 30,
	2007			2006

Retail customers purchasing energy from a competitive electric generation supplier:
Number of customers at period end		31,700			38,300
Percentage of total retail customers		2	%		3	%
Volume (GWhs)(a)		158			188
Percentage of total retail deliveries		2	%		2	%


(a)		One GWh is the equivalent of one million kWh.

The increase in electric retail revenue and expense associated with customer choice reflects customers, primarily from the small commercial and industrial customer class, returning to PECO as their electric supplier.

Other rate changes and mix

Revenues. The decrease in electric and gas revenues attributable to other rate changes and mix reflects the effects of rate blocking, whereby certain customer charges per unit of energy are reduced when customer usage exceeds a certain threshold.

Purchased Power and Fuel Expense. The increase in purchased power attributable to other rate changes and mix reflects a change in the mix of average pricing related to PECO’s PPA with Generation.

Other revenues and expenses

Revenues. The increase in electric and gas revenues was primarily due to increased late charges.

Purchased Power and Fuel. The decrease in purchased power was due to various factors, none of which were individually material.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Wages and salaries	$	4
Storm costs		3
Allowance for uncollectible accounts expense		(4	)
Other		2

Increase in operating and maintenance expense	$	5

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the three months ended June 30, 2007 compared to the same period in 2006 was primarily due to an increase in CTC amortization of $15 million. PECO’s additional amortization of the CTC is in accordance with its original settlement under the Competition Act.

115

Taxes Other Than Income. The changes in taxes other than income for the three months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Taxes on utility revenues(a)	$	7
State franchise tax adjustment in 2006(b)		7
Sales and use tax adjustment in 2006(b)		5
Other		(1	)

Increase in taxes other than income	$	18


(a)		As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in tax expense was offset by a corresponding increase in revenues.

(b)		Represents the reduction of tax accruals in the second quarter of 2006 following settlements related to 2005 tax assessments.

Interest Expense, Net. The decrease in interest expense, net for the three months ended June 30, 2007 compared to the same period in 2006 was primarily due to scheduled payments on long-term debt owed to PECO Energy Transition Trust (PETT), partially offset by an increase in interest expense associated with a higher amount of outstanding long-term First and Refunding Mortgage Bonds.

Other, Net. The increase for the three months ended June 30, 2007 compared to the same period in 2006 was primarily due to interest income associated with the adoption of FIN 48. See Note 14 of the Combined Notes to Consolidated Financial Statements for further details of the components of other, net. See Notes 3 and 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the adoption of FIN 48.

Income Taxes. The effective income tax rate was 36.4% for the three months ended June 30, 2007 compared to 32.6% for the three months ended June 30, 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail

PECO’s electric sales statistics and revenue detail were as follows:


	Three Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2007		2006		Variance			% Change

Full service(a)
Residential		2,963		2,719		244			9.0	%
Small commercial & industrial		1,995		1,869		126			6.7	%
Large commercial & industrial		4,054		3,875		179			4.6	%
Public authorities & electric railroads		202		229		(27	)		(11.8	)%

Total full service		9,214		8,692		522			6.0	%

Delivery only(b)
Residential		10		14		(4	)		(28.6	)%
Small commercial & industrial		145		163		(18	)		(11.0	)%
Large commercial & industrial		3		11		(8	)		(72.7	)%

Total delivery only		158		188		(30	)		(16.0	)%

Total retail deliveries		9,372		8,880		492			5.5	%


(a)		Full service reflects deliveries to customers taking electric service under tariff rates.

(b)		Delivery only service reflects customers receiving electric generation service from a competitive electric generation supplier.

116


	Three Months
	Ended
	June 30,
Electric Revenue	2007		2006		Variance			% Change

Full service(a)
Residential	$	445	$	392	$	53			13.5	%
Small commercial & industrial		265		236		29			12.3	%
Large commercial & industrial		341		319		22			6.9	%
Public authorities & electric railroads		21		22		(1	)		(4.5	)%

Total full service		1,072		969		103			10.6	%

Delivery only(b)
Residential		1		1		—			0.0	%
Small commercial & industrial		8		9		(1	)		(11.1	)%
Large commercial & industrial		—		1		(1	)		(100.0	)%

Total delivery only		9		11		(2	)		(18.2	)%

Total electric retail revenues		1,081		980		101			10.3	%

Other revenue(c)		66		60		6			10.0	%

Total electric and other revenue	$	1,147	$	1,040	$	107			10.3	%


(a)		Full service revenue reflects revenue from customers taking generation service under tariff rates, which include the cost of energy, the cost of transmission and distribution of the energy and a CTC.

(b)		Delivery only revenue reflects revenue from customers receiving generation service from a competitive electric generation supplier, which includes the cost of distribution of the energy and a CTC.

(c)		Other revenues include transmission revenue from PJM and other wholesale energy sales.

PECO Gas Sales Statistics and Revenue Detail

PECO’s gas sales statistics and revenue detail were as follows:


	Three Months Ended June 30,
Deliveries to customers (in million cubic feet (mmcf))	2007		2006		Variance			% Change

Retail sales		8,317		6,292		2,025			32.2	%
Transportation		5,928		6,139		(211	)		(3.4	)%

Total		14,245		12,431		1,814			14.6	%


	Three Months Ended June 30,
Revenue	2007		2006		Variance			% Change

Retail sales	$	116	$	103	$	13			12.6	%
Transportation		3		4		(1	)		(25.0	)%
Resales and other		3		1		2			n.m.

Total gas revenue	$	122	$	108	$	14			13.0	%

n.m. Not meaningful

117

Results of Operations — Exelon Corporation

Six Months Ended June 30, 2007 Compared To Six Months Ended June 30, 2006


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
Exelon Corporation	2007			2006			Variance

Operating revenues	$	9,330		$	7,559		$	1,771
Operating expenses
Purchased power and fuel expense		3,655			2,534			(1,121	)
Operating and maintenance expense		2,120			1,906			(214	)
Depreciation and amortization		738			735			(3	)
Taxes other than income		395			364			(31	)

Total operating expenses		6,908			5,539			(1,369	)

Operating income		2,422			2,020			402

Other income and deductions
Interest expense		(318	)		(306	)		(12	)
Interest expense to affiliates, net		(109	)		(139	)		30
Equity in losses of unconsolidated affiliates and investments		(69	)		(61	)		(8	)
Other, net		106			91			15

Total other income and deductions		(390	)		(415	)		25

Income from continuing operations before income taxes		2,032			1,605			427
Income taxes		648			564			(84	)

Income from continuing operations		1,384			1,041			343
Income from discontinued operations, net of income taxes		9			3			6

Net income	$	1,393		$	1,044		$	349

Diluted earnings per share	$	2.05		$	1.55		$	0.50

Net Income. Exelon’s net income for the six months ended June 30, 2007 reflects higher average margins on wholesale market sales; higher nuclear output at Generation; decreased nuclear refueling outage costs; a favorable PJM billing settlement with PPL; favorable weather conditions in the ComEd and PECO service territories; increased electric and gas deliveries, excluding the effects of weather, at ComEd and PECO; increased pricing for delivery services at ComEd and PECO; increased transmission revenues at ComEd; and increased earnings associated with investments in synthetic fuel-producing facilities. These increases were partially offset by unrealized mark-to-market losses on contracts not yet settled; decreased energy margins at ComEd; higher operating and maintenance expenses, including labor-related inflation and increased allowance for uncollectible accounts expense at ComEd; the impact of ComEd’s 2007 rate relief program and other post rate freeze period transition expenses; increased depreciation and amortization expense, primarily related to CTC amortization at PECO; an update of the nuclear decommissioning asset retirement obligation recorded in the second quarter of 2006; and favorable tax settlements at PECO in 2006.

Operating Revenues. Operating revenues increased due to an increase in wholesale and retail electric sales at Generation due to higher volumes of generation sold to the market as a result of the expiration of the ComEd PPA in 2006; higher market prices; favorable weather conditions in the ComEd and PECO service territories; higher electric and gas delivery volumes, excluding the effects of weather and customer choice, at ComEd and PECO; rate changes and mix at ComEd due to the end of the rate freeze and implementation of market-based rates for electricity; impact of the distribution rate increase; and increased transmission revenues at ComEd resulting from the 2007 transmission rate case and increased load. These increases were partially offset by ComEd customers

118

switching to competitive electric generation suppliers and the impact of ComEd’s 2007 rate relief program. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense. Purchased power and fuel expense increased due to higher volumes of power purchased in the market and higher market energy prices. Purchased power represented 19% of Generation’s total supply for the six months ended June 30, 2007 and compared to 17% for the six months ended June 30, 2006. This increase was partially offset by a favorable PJM billing settlement with PPL. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to labor-related inflation; the impact of ComEd’s 2007 rate relief program and other post rate freeze period transition expenses; increased allowance for uncollectible accounts expense at ComEd; and a decrease in Generation’s nuclear decommissioning obligation related to the AmerGen nuclear plants recorded in the second quarter of 2006. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO. This increase was partially offset by lower amortization related to investments in synthetic fuel-producing facilities.

Taxes Other Than Income. Taxes other than income increased primarily due to favorable tax settlements at PECO in 2006 and higher taxes on utility revenues at PECO in 2007.

Other Income and Deductions. The change in other income and deductions reflects interest income related to the favorable PJM billing settlement with PPL, a gain related to the sale of investments by Generation, earnings associated with investments in synthetic fuel-producing facilities and expenses recorded in 2006 related to the now terminated merger with PSEG.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 31.9% for the six months ended June 30, 2007 compared to 35.1% for the six months ended June 30, 2006. The synthetic-fuel producing facilities credit decreased the effective income tax rate from continuing operations by 5.6% for the six months ended June 30, 2007. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, Exelon has sold or wound down substantially all components of Enterprises. Accordingly, the results of operations and any gain or loss on the sale of these entities have been presented as discontinued operations within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations and Comprehensive Income. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations.

During the six months ended June 30, 2007, Exelon’s Consolidated Statement of Income and Comprehensive Income included $9 million (after-tax) of income from discontinued operations related to a favorable legal settlement at Enterprises and $3 million (after-tax) of income from discontinued operations related primarily to Sithe, resulting from a settlement agreement between a subsidiary of Sithe, the Pennsylvania Attorney General’s Office and the Pennsylvania Department of Revenue regarding a previously disputed tax position asserted for the 2000 tax year.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the six months ended June 30, 2007 compared to the same period in 2006 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

119

Income (Loss) from Continuing Operations by Business Segment


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Generation	$	1,133		$	765		$	368
ComEd		33			181			(148	)
PECO		224			186			38
Other(a)		(6	)		(91	)		85

Total	$	1,384		$	1,041		$	343


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

Net Income (Loss) by Business Segment


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Generation	$	1,138		$	768		$	370
ComEd		33			181			(148	)
PECO		224			186			38
Other(a)		(2	)		(91	)		89

Total	$	1,393		$	1,044		$	349


(a)		Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

120

Results of Operations — Generation


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	5,344		$	4,434		$	910
Operating expenses
Purchased power and fuel		2,038			1,817			(221	)
Operating and maintenance		1,257			1,108			(149	)
Depreciation and amortization		133			139			6
Taxes other than income		88			84			(4	)

Total operating expenses		3,516			3,148			(368	)

Operating income		1,828			1,286			542

Other income and deductions
Interest expense		(66	)		(82	)		16
Equity in earnings (losses) of investments		1			(5	)		6
Other, net		54			20			34

Total other income and deductions		(11	)		(67	)		56

Income from continuing operations before income taxes		1,817			1,219			598
Income taxes		684			454			(230	)

Income from continuing operations		1,133			765			368
Income from discontinued operations, net of income taxes		5			3			2

Net income	$	1,138		$	768		$	370

Net Income. Generation’s net income for the six months ended June 30, 2007 compared to the same period in 2006 increased primarily due to higher revenue, net of purchased power and fuel expense, offset by increased operating and maintenance expense, primarily associated with an update of the nuclear decommissioning asset retirement obligation recorded in the second quarter of 2006, higher nuclear refueling outage expenses and wage-related inflation. Generation’s revenue, net of purchased power and fuel expense, increased by $689 million for the six months ended June 30, 2007 compared to the same period in 2006, which was driven by higher average margins primarily due to the end of the below-market price PPA with ComEd at the end of 2006, the contractual increase in the prices associated with Generation’s PPA with PECO, and by a PJM billing settlement with PPL. In addition to these impacts, Generation’s net income for the six months ended June 30, 2007 included (all after tax) a gain on the sale of investments of $11 million and earnings of $5 million associated with the settlement of a tax matter related to Generation’s previous investment in Sithe.

121

Operating Revenues. For the six months ended June 30, 2007 and 2006, Generation’s sales were as follows:


	Six Months
	Ended
	June 30,
Revenue	2007		2006		Variance			% Change

Electric sales to affiliates	$	1,688	$	2,270	$	(582	)		(25.6	)%
Wholesale and retail electric sales		3,317		1,689		1,628			96.4	%

Total electric sales revenue		5,005		3,959		1,046			26.4	%
Retail gas sales		269		340		(71	)		(20.9	)%
Trading portfolio		32		5		27			n.m.
Other operating revenue(a)		38		130		(92	)		(70.7	)%

Total operating revenue	$	5,344	$	4,434	$	910			20.5	%


(a)		Includes sales relating to fossil fuel sales, operating service agreements and decommissioning revenue from PECO in 2007 and tolling agreements, fossil fuel sales, operating service agreements and decommissioning revenue from ComEd and PECO in 2006.


n.m.		Not meaningful.


	Six Months
	Ended
	June 30,
Sales (in GWhs)	2007		2006		Variance			% Change

Electric sales to affiliates		31,083		57,870		(26,787	)		(46.3	)%
Wholesale and retail electric sales		61,740		33,052		28,688			86.8	%

Total electric sales		92,823		90,922		1,901			2.1	%

Trading volumes of 9,876 GWhs and 14,754 GWhs for the six months ended June 30, 2007 and 2006 respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $582 million for the six months ended June 30, 2007, as compared to the same period in 2006. The decrease was primarily due to a $970 million decrease from lower electric sales volume, partially offset by higher prices resulting in a $388 million increase in revenues.

In the ComEd territories, lower volumes resulted in a $1,021 million decrease in revenues, partially offset by a $306 million increase in revenues due to higher prices. Generation’s PPA with ComEd expired December 31, 2006. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation is selling more power through bilateral agreements, which resulted in higher prices, but a decrease in volumes to ComEd.

In the PECO territories, higher prices resulted in increased revenues of $82 million due to a scheduled electric generation rate increase that took effect January 1, 2007. Additionally, volumes increased resulting in increased revenues of $51 million.

Wholesale and retail electric sales. The increase in Generation’s wholesale and retail electric sales for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase

Volume	$	1,483
Price		145

Increase in wholesale and retail electric sales	$	1,628

Wholesale and retail electric sales increased $1,628 million for the six months ended June 30, 2007 as compared to the same period in 2006. The increase was the result of higher volumes of generation sold to the market as a result of the expiration of the ComEd PPA in 2006.

122

Retail gas sales. Retail gas sales decreased $71 million for the six months ended June 30, 2007 as compared to the same period in 2006, of which $41 million was due to lower realized prices and $30 million was due to lower volumes as a result of lower demand.

Other revenue. The decrease in other revenues for the six months ended June 30, 2007 compared to the same period in 2006 was due to a $32 million decrease related to the termination of decommissioning collections from ComEd in accordance with the terms and conditions of the ICC Order which only permitted such collections through December 31, 2006. There was a decrease of $36 million due to the cessation of a tolling agreement. Additionally, a $24 million decrease in other revenues was attributable to the sale of TEG and TEP on February 9, 2007 and the resulting absence of revenue thereafter.

Purchased Power and Fuel Expense. Generation’s supply sources are summarized below:


	Six Months
	Ended
	June 30,
Supply Source (in GWhs)	2007		2006		Variance			% Change

Nuclear generation(a)		69,707		68,933		774			1.1	%
Purchases — economic hedge portfolio		17,263		15,870		1,393			8.8	%
Fossil and hydroelectric generation		5,853		6,119		(266	)		(4.3	)%

Total supply		92,823		90,922		1,901			2.1	%


(a)		Represents Generation’s proportionate share of the output of its nuclear generating plants, including Salem, which is operated by PSEG Nuclear, LLC.

The changes in Generation’s purchased power and fuel expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


							Increase
	Price			Volume			(Decrease)

Purchased power costs	$	6		$	122		$	128
Generation cost		(10	)		3			(7	)
Fuel resale cost		(45	)		(28	)		(73	)
Mark-to-market		n.m.			n.m.			173

Increase in purchased power and fuel expense							$	221

n.m. Not meaningful

Purchased Power Cost. Purchased power cost includes all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation experienced overall higher volumes that were attributable to increased purchases from PPAs and to serve load commitments. These increases were partially offset by lower purchased power volumes needed to supply ComEd due to the expiration of the PPA at December 31, 2006. Further, Generation realized overall lower prices for purchased power. Additionally, Generation’s purchased power cost decreased $28 million due to the PJM billing dispute settlement with PPL. See Note 13 of the Combined Notes to Consolidated Financial Statements.

Generation Cost. Generation cost includes fuel cost for internally generated energy. Generation experienced overall lower generation costs for the six months ended June 30, 2007 as compared to the same period in 2006 due to decreased prices related to fossil fuel generation. The increased volume of $3 million was primarily due to higher nuclear generation.

Fuel Resale Cost. Fuel resale cost includes retail gas purchases and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs for the six months ended June 30, 2007 as compared to the same period in 2006 consisted of overall lower prices resulting in a decrease of $45 million. Additionally, a decrease of $28 million was the result of lower volumes caused by lower demand.

123

Mark-to-market. Mark-to-market losses on power hedging activities were $145 million for the six months ended June 30, 2007 compared to gains of $88 million for the same period in 2006. Mark-to-market gains on fuel hedging activities were $8 million for the six months ended June 30, 2007 compared to losses of $52 million for the same period in 2006.

Generation’s average margins per MWh of electricity sold during the six months ended June 30, 2007 and 2006 were as follows:


	Six Months
	Ended
	June 30,
($/MWh)	2007		2006		% Change

Average electric revenue
Electric sales to affiliates	$	54.31	$	39.23		38.4	%
Wholesale and retail electric sales		53.73		51.10		5.1	%
Total — excluding the trading portfolio		53.92		43.54		23.8	%
Average electric supply cost(a) — excluding the trading portfolio		19.08		16.23		17.6	%
Average margin — excluding the trading portfolio		34.84		27.31		27.6	%


(a)		Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales and other sales.

Nuclear fleet operating data for the six months ended June 30, 2007 and 2006 were as follows:


	Six Months
	Ended
	June 30,
	2007			2006

Nuclear fleet capacity factor(a)		95.0	%		93.3	%
Nuclear fleet production cost per MWh(a)	$	14.28		$	14.19


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor increased primarily due to fewer planned refueling outage and non-refueling outage days during the six months ended June 30, 2007 compared to the same period in 2006. For the six months ended June 30, 2007 and 2006, refueling outage days totaled 95 and 114, respectively, and non-refueling outage days totaled 19 and 49, respectively. Additionally, during the six months ended June 30, 2007, both Quad Cities units operated at Extended Power Uprate (EPU) generation levels for the entire period as compared to the six months ended June 30, 2006, when the generation levels of both Quad Cities units operated intermittently at pre-EPU generation levels during that period to address vibration related equipment issues. The higher number of net MWh’s generated was offset by labor-related inflation and higher costs for nuclear fuel, NRC reactor fees, and security, resulting in a slightly higher production cost per MWh for the six months ended June 30, 2007 as compared to the same period in 2006.

Operating and Maintenance Expense. The increase in operating and maintenance expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Decommissioning-related activities	$	118
Pension, payroll and benefit costs		43
Nuclear refueling outage costs		(9	)
Other		(3	)

Increase in operating and maintenance expense	$	149

124

The net $149 million increase was primarily attributable to the following:


	•	A $118 million increase in nuclear decommissioning-related activities was associated with the recognition of a credit totaling $149 million which represented a reduction in the asset retirement obligation in excess of the asset retirement cost balance for the AmerGen units recorded in the same period in 2006, offset by a $31 million decrease resulting from the termination of revenue collections from ComEd, which likewise no longer required an offset through operating and maintenance expense.

	•	A $43 million increase in pension, payroll and benefit costs reflected the impact of inflation as well as an increase in various direct and allocated fringe costs.

	•	A $9 million decrease in nuclear refueling outage costs was associated with the fewer planned refueling outage days during the six months ended June 30, 2007 as compared to the same period in 2006.

	•	A $3 million decrease in other operating and maintenance expense for the six months ended June 30, 2007 compared to the same period in 2006 was primarily due to a decrease in service agreement-related expenses, offset by an increase in contracting charges resulting from increased outage costs for fossil and hydroelectric facilities.

Depreciation and Amortization. The decrease in depreciation and amortization expense for the six months ended June 30, 2007 compared to the same period in 2006 was primarily due to the reassessment of the useful lives, for accounting purposes, of several fossil facilities.

Interest Expense. The decrease in net interest expense for the six months ended June 30, 2007 as compared to the same period in 2006 was primarily attributable to an interest payment made in 2006 to the Internal Revenue Service (IRS) in settlement of a tax matter and to a decline in the amount of commercial paper that was outstanding during the six months ended June 30, 2007 as compared to the same period in 2006.

Other, Net. The change in other, net reflects a gain on sale of investments recognized in the first and second quarters of 2007.

Effective Income Tax Rate. There was not a significant change in the effective income tax rate for the six months ended June 30, 2007 compared to the same period in 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Operations and Comprehensive Income.

For the six months ended June 30, 2007, Generation’s Consolidated Statement of Income and Comprehensive Income included $5 million (after-tax) gain on disposal of discontinued operations related primarily to Sithe, resulting from a settlement agreement between a subsidiary of Sithe, the Pennsylvania Attorney General’s Office and the Pennsylvania Department of Revenue regarding a previously disputed tax position asserted for the 2000 tax year. For the six months ended June 30, 2006, Generation’s Consolidated Statement of Income and Comprehensive Income included $3 million (after-tax) gain on disposal of discontinued operations. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

125

Results of Operations — ComEd


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	2,911		$	2,880		$	31
Operating expenses
Purchased power		1,806			1,628			(178	)
Operating and maintenance		510			434			(76	)
Depreciation and amortization		217			205			(12	)
Taxes other than income		157			152			(5	)

Total operating expenses		2,690			2,419			(271	)

Operating income		221			461			(240	)

Other income and deductions
Interest expense, net		(170	)		(153	)		(17	)
Equity in losses of unconsolidated affiliates		(4	)		(5	)		1
Other, net		7			1			6

Total other income and deductions		(167	)		(157	)		(10	)

Income before income taxes		54			304			(250	)
Income taxes		21			123			102

Net income	$	33		$	181		$	(148	)

Net Income. As more fully described below, ComEd’s net income for the six months ended June 30, 2007 compared to the same period in 2006 reflected higher purchased power expense, higher operating and maintenance expense, higher depreciation and amortization expense and higher interest expense. Beginning in 2007, ComEd ceased earning margin on the energy component of its deliveries to its customers, nor is it collecting CTC revenues. While ComEd’s 2007 results reflect an $83 million annual rate increase as allowed by the ICC, this rate increase was based generally on 2004 costs and does not include the impacts of increased operating expenses since 2004 or additional net capital investment since the end of 2005. ComEd anticipates filing a new delivery service rate case during the third quarter of 2007 based on a 2006 test year and also filed a transmission rate case during the first quarter 2007. On June 5, 2007, FERC issued an order for the transmission rate case conditionally approving ComEd’s proposal to implement a formula based transmission rate effective May 1, 2007, subject to refund. The requested rate increase is designed to help reduce the regulatory lag related to recovery of these costs and returns on ComEd’s investments. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion. In 2007, ComEd incurred increased costs associated with transitioning from the rate freeze period including implementing the Rate Relief and Rate Stabilization programs.

126

Operating Revenues and Purchased Power Expense. The changes in operating revenues and purchased power expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase (Decrease)
	Operating			Purchased			Revenue Net of
	Revenues			Power			Purchased Power

Customer choice	$	(604	)	$	(463	)	$	(141	)
Rate changes and mix		521			603			(82	)
Rate Relief Program		(19	)		—			(19	)
Transmission		32			(6	)		38
Weather		89			53			36
Volume		11			—			11
Other		1			(9	)		10

Total increase (decrease)	$	31		$	178		$	(147	)

Customer choice

As a result of ComEd’s higher electricity rates, more non-residential customers have elected to have a competitive electric generation supplier provide their electricity. For the six months ended June 30, 2007 and 2006, 48% and 21%, respectively, of electricity delivered to ComEd’s retail customers was provided by competitive electric generation suppliers. Most of the customers previously receiving electricity under the PPO are now electing either to buy their electricity from a competitive electric generation supplier or from ComEd under tariff rates.


	Six Months
	Ended June 30,
	2007			2006

Retail customers purchasing electricity from a competitive electric generation supplier:
Volume (GWhs)(a)		21,361			8,908
Percentage of total retail deliveries		48	%		21	%
Retail customers purchasing electricity from a competitive electric generation supplier or the ComEd PPO:
Number of customers at period end		41,500			16,100
Percentage of total retail customers		1	%		(b	)
Volume (GWhs)(a)		21,418			13,428
Percentage of total retail deliveries		48	%		31	%


(a)		One GWh is the equivalent of one million kilowatthours (kWh).

(b)		Less than one percent.

127

Rate changes and mix

Revenue. The increase in revenue related to rate changes and mix primarily reflects the end of the rate freeze and the implementation of market-based rates for electricity and the impact of the distribution rate increase. In 2006, most customers were charged a bundled rate that included distribution, transmission and the cost of electricity. Additionally, under Illinois law, no CTCs are permitted to be collected after 2006. As of January 2007, ComEd began billing customers on an unbundled basis, which includes separate charges for distribution, transmission and electricity. Given the relatively small increase approved by the ICC in the annual distribution rates of $83 million, the majority of the change in year over year pricing is driven by the inclusion of market-based electricity rates. The market-based electricity rates were determined through the reverse-auction competitive bidding process. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information. Additionally starting in 2007, ComEd is recovering former manufacturing gas plant remediation costs from customers.

Rate Relief Program

Transmission

Purchased Power. Effective December 1, 2004, PJM became obligated to pay Seams Elimination Charge/Cost Adjustment/Assignment (SECA) collections to ComEd and ComEd became obligated to pay SECA charges. These charges were being collected subject to refund as they are being disputed. ComEd recorded SECA collections and payments on a net basis through purchased power expense. As ComEd was a net collector of SECA charges, ComEd recorded $5 million of net SECA collections during the three months ended March 31, 2006. During the three months ended March 31, 2006, ComEd adjusted its reserve for SECA to reflect management’s best estimate of amounts that will ultimately be required to be refunded. The reserve existing at June 30, 2007 continues to represent management’s best estimate. Management of ComEd believes that the appropriate reserve has been established in the event that some portion of SECA collections are required to be refunded. SECA charges expired on March 31, 2006. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

Weather

Revenue. Revenues were higher due to favorable weather conditions for the six months ended June 30, 2007 compared to the same period in 2006. In ComEd’s service territory, heating degree days were 14% higher and cooling degree days were 46% higher during the six months ended June 30, 2007 compared to the same period in 2006.

Purchased Power. The increase in purchased power expense attributable to weather was resulting from higher demand due to favorable weather conditions in the ComEd service territory relative to the prior year.

128

Volume

Other

Revenue — Economic Hedge Derivative Contracts. During the six months ended June 30, 2007 as compared to the six months ended June 30, 2006, ComEd had a net $5 million increase in economic hedge derivative contracts activity, including mark-to-market adjustments and settlements.

Revenue — Wholesale Contracts. ComEd’s revenue decreased $11 million as a result of certain wholesale contracts expiring in May 2007.

Purchased Power — Wholesale Contracts. ComEd’s purchased power decreased $8 million as a result of certain wholesale contracts expiring in May 2007.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase

Post rate freeze period transition expenses(a)	$	21
Allowance for uncollectible accounts expense(b)		13
Wages and salaries		9
Contracting		7
Fringe benefits(c)		7
Severance-related expenses		4
Corporate allocations		2
Repair and maintenance of transformer and synchronous condenser		3
Materials and supplies expense		2
Rents and leases		2
Other		6

Increase in operating and maintenance expense	$	76


(a)		Includes increased advertising costs, costs associated with the Rate Relief and CARE programs of $8 million, costs associated with implementing ComEd’s Rate Stabilization plan and other costs associated with transitioning to the post rate freeze period. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information.

(b)		Reflects the impact of higher revenues due to increased customer receivables resulting from the inclusion of market-based electricity rates and higher delivery rates. Also reflects an increase in older outstanding receivable balances from customers as a result of a management decision to reduce the number of non-paying customers being disconnected.

(c)		Reflects increases in various fringe benefits primarily due to increased pension and other postretirement benefits costs of $8 million.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase

Depreciation expense associated with higher plant balances	$	10
Amortization of regulatory assets		2

Increase in depreciation and amortization expense	$	12

In 2007, ComEd’s amortization reflects the initial amortization of the various regulatory assets authorized by the ICC in its 2006 orders, partially offset by the impacts of the elimination of the regulatory asset for recoverable transition costs. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information.

129

Taxes Other Than Income. Taxes other than income increased for the six months ended June 30, 2007 compared to the same period in 2006 as a result of an increase in the Illinois Electricity Distribution tax and an increase in real estate and property taxes.

Interest Expense, Net. The increase in interest expense, net for the six months ended June 30, 2007 compared to the same period in 2006 primarily resulted from higher debt balances and higher interest rates. Also in 2007, ComEd’s interest expense, net reflected $7 million of the initial amortization of the regulatory asset related to the early debt retirement costs authorized by the ICC in 2006.

Other, Net. Other, net increased for the six months ended June 30, 2007 compared to the same period in 2006. The changes consisted of the following:


	Increase

Gain on disposal of assets and investments, net	$	3
Allowance for funds used during construction, equity		2
Other		1

Increase in other, net	$	6

Income Taxes. The effective income tax rate was 38.9% for the six months ended June 30, 2007 compared to 40.5% for the six months ended June 30, 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

ComEd Electric Operating Statistics and Revenue Detail


	Six Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2007		2006		Variance			% Change

Full service(a)
Residential		13,448		12,921		527			4.1	%
Small commercial & industrial		8,421		11,028		(2,607	)		(23.6	)%
Large commercial & industrial		1,245		4,609		(3,364	)		(73.0	)%
Public authorities & electric railroads		396		1,115		(719	)		(64.5	)%

Total full service		23,510		29,673		(6,163	)		(20.8	)%

PPO
Small commercial & industrial		23		2,322		(2,299	)		(99.0	)%
Large commercial & industrial		34		2,198		(2,164	)		(98.5	)%

		57		4,520		(4,463	)		(98.7	)%

Delivery only(b)
Small commercial & industrial		7,885		2,185		5,700			n.m.
Large commercial & industrial		13,208		6,723		6,485			96.5	%
Public authorities & electric railroads		268		—		268			n.m.

		21,361		8,908		12,453			139.8	%

Total PPO and delivery only		21,418		13,428		7,990			59.5	%

Total retail deliveries		44,928		43,101		1,827			4.2	%


(a)		Full service reflects deliveries to customers taking electric service under tariff rates.

(b)		Delivery only service reflects customers electing to receive electricity from a competitive electric generation supplier.

n.m. Not meaningful.

130


	Six Months
	Ended
	June 30,
Electric Revenue	2007			2006			Variance			% Change

Full service(a)
Residential	$	1,423		$	1,096		$	327			29.8	%
Small commercial & industrial		814			839			(25	)		(3.0	)%
Large commercial & industrial		96			240			(144	)		(60.0	)%
Public authorities & electric railroads		34			68			(34	)		(50.0	)%

Total full service		2,367			2,243			124			5.5	%

PPO(b)
Small commercial & industrial		2			163			(161	)		(98.8	)%
Large commercial & industrial		3			132			(129	)		(97.7	)%

		5			295			(290	)		(98.3	)%

Delivery only(c)
Small commercial & industrial		119			33			86			n.m.
Large commercial & industrial		134			67			67			100.0	%
Public authorities & electric railroads		3			—			3			n.m.

		256			100			156			156.0	%

Total PPO and delivery only		261			395			(134	)		(33.9	)%

Total electric retail revenues		2,628			2,638			(10	)		(0.4	)%
Other revenue(d)		285			250			35			14.0	%
Economic hedge derivative contracts		(2	)		(8	)		6			(75.0	)%

Total operating revenues	$	2,911		$	2,880		$	31			1.1	%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariff rates, which include the cost of electricity and the cost of transmission and distribution of the electricity.

(b)		Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC through December 31, 2006.

(c)		Delivery only revenues reflect revenue under tariff rates from customers electing to receive electricity from a competitive electric generation supplier, which includes a distribution charge and a CTC through December 31, 2006.

(d)		Other revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

n.m. Not meaningful.

131

Results of Operations — PECO


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2007			2006			Variance

Operating revenues	$	2,769		$	2,554		$	215
Operating expenses
Purchased power and fuel		1,498			1,389			(109	)
Operating and maintenance		294			289			(5	)
Depreciation and amortization		370			343			(27	)
Taxes other than income		142			117			(25	)

Total operating expenses		2,304			2,138			(166	)

Operating income		465			416			49

Other income and deductions
Interest expense, net		(126	)		(136	)		10
Equity in losses of unconsolidated affiliates		(4	)		(6	)		2
Other, net		10			5			5

Total other income and deductions		(120	)		(137	)		17

Income before income taxes		345			279			66
Income taxes		121			93			(28	)

Net income		224			186			38
Preferred stock dividends		2			2			—

Net income on common stock	$	222		$	184		$	38

Net Income. PECO’s net income for the six months ended June 30, 2007 compared to the same period in 2006 increased primarily due to higher operating revenues, net of purchased power and fuel expense, which reflected increased sales from favorable weather conditions, increased usage across all customer classes, the completion of certain authorized rate increases which began in 2006 and the favorable settlement of a PJM billing dispute. Partially offsetting higher operating revenues, net of purchased power and fuel expense, was higher CTC amortization, which was in accordance with the Competition Act.

Electric and Gas Operating Revenues, Purchased Power and Fuel Expense. The changes in PECO’s operating revenues and purchased power and fuel expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase (Decrease)
	Electric									Gas									Total
																						Purchased
	Operating			Purchased						Operating			Fuel						Operating			Power
	Revenues			Power			Net			Revenues			Expense			Net			Revenues			and Fuel			Net

Weather	$	61		$	26		$	35		$	81		$	67		$	14		$	142		$	93		$	49
Volume		57			24			33			17			14			3			74			38			36
Rate increases (decreases)		99			88			11			(120	)		(120	)		—			(21	)		(32	)		11
Settlement of PJM billing dispute		—			(10	)		10			—			—			—			—			(10	)		10
Customer choice		5			5			—			—			—			—			5			5			—
Other rate changes and mix		(13	)		—			(13	)		(3	)		7			(10	)		(16	)		7			(23	)
Other		13			(7	)		20			18			15			3			31			8			23

Total increase (decrease)	$	222		$	126		$	96		$	(7	)	$	(17	)	$	10		$	215		$	109		$	106

132

Weather

Revenues. Revenues were higher due to favorable weather conditions in PECO’s service territory, where heating degree days and cooling degree days were 19% and 21% higher, respectively, during the six months ended June 30, 2007 compared to the same period in 2006.

Volume

Revenues. The increase in revenues as a result of higher delivery volume, exclusive of the effects of weather and customer choice, reflected increased usage across all customer classes for electric and gas. In addition, there was a favorable impact of an increased number of customers primarily in the residential and small commercial and industrial classes for electric and gas.

Purchased Power and Fuel Expense. The increase in expenses as a result of higher delivery volume, exclusive of the effects of weather and customer choice, reflected increased usage across all customer classes for electric and gas and the impact of an increased number of customers primarily in the residential and small commercial and industrial classes for electric and gas.

Rate increases (decreases)

Revenues. The increase in electric revenues attributable to electric rate increases reflected $11 million associated with the completion in January 2007 of scheduled CTC and distribution rate increases which began in 2006. In addition, effective for customer bills for electric generation service delivered after customers’ January 2007 meter readings, a scheduled electric generation rate increase took effect, which represents the last scheduled rate increase through 2010 under PECO’s 1998 restructuring settlement. This rate increase does not affect operating income as PECO will incur corresponding and offsetting purchased power expense under its PPA with Generation. The decrease in gas revenues was due to net decreases in rates through PAPUC-approved quarterly changes to the purchased gas adjustment clause. The average purchased gas cost rate per million cubic feet in effect for the six months ended June 30, 2007 was 18% lower than the average rate for the same period in 2006.

Purchased Power and Fuel Expense. The increase in purchased power expense attributable to electric rate increase reflects the scheduled generation rate increase under the PPA with Generation. The decrease in fuel expense reflects lower gas prices.

Settlement of PJM billing dispute

Purchased Power. PECO’s purchased power expense decreased $10 million due to the settlement of a PJM billing dispute with PPL. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion.

Customer choice

Revenues and Purchased Power. For the six months ended June 30, 2007 and 2006, 2% of energy delivered to PECO’s retail customers was provided by competitive electric generation suppliers.

133


	Six Months
	Ended
	June 30,
	2007			2006

Retail customers purchasing energy from a competitive electric generation supplier:
Number of customers at period end		31,700			38,300
Percentage of total retail customers		2	%		3	%
Volume (GWhs)(a)		317			406
Percentage of total retail deliveries		2	%		2	%


(a)		One GWh is the equivalent of one million kWh.

Other rate changes and mix

Revenues. The decrease in electric and gas revenues attributable to other rate changes and mix primarily reflects the effects of rate blocking, whereby certain customer charges per unit of energy are reduced when customer usage exceeds a certain threshold.

Purchased Power and Fuel Expense. The increase in fuel expense reflects a timing difference between how fuel costs are recognized and the fuel commodity component in customers’ rates.

Other revenues and expenses

Revenues. The increase in electric revenues was primarily due to increased late charges. The increase in gas revenues was primarily due to increased off-system sales.

Purchased Power and Fuel. The increase in gas fuel expense was due to increased off-system sales.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

Contractors	$	7
Wages and salaries		5
Environmental reserve(a)		4
Allowance for uncollectible accounts expense(b)		(11	)

Increase in operating and maintenance expense	$	5


(a)		Reflects lower expense in 2006 due to a settlement related to a Superfund site in the first quarter of 2006.

(b)		Reflects the following factors, each of which decreased expense in 2007 compared to 2006; (1) lower net charge-offs of customer receivables in 2007 compared to 2006; (2) changes in PAPUC-approved regulations which relaxed customer payment terms in 2006, which resulted in higher expense in 2006.

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Depreciation and Amortization Expense. The changes in depreciation and amortization expense for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase
	(Decrease)

CTC amortization(a)	$	32
Accelerated amortization of PECO billing system(b)		(7	)
Other		2

Increase in depreciation and amortization expense	$	27


(a)		PECO’s additional amortization of the CTC is in accordance with its original settlement under the Competition Act.

(b)		In January 2005, as part of a broader systems strategy at PECO associated with the proposed merger with PSEG, Exelon’s Board of Directors approved the implementation of a new customer information and billing system at PECO. The approval of this new system required the accelerated amortization of PECO’s current system through 2006 and the recognition of additional amortization expense in 2005 and 2006. The new system was implemented in the fourth quarter 2006.

Taxes Other Than Income. The changes in taxes other than income for the six months ended June 30, 2007 compared to the same period in 2006 consisted of the following:


	Increase

Taxes on utility revenues(a)	$	13
State franchise tax adjustment in 2006(b)		7
Sales and use tax adjustment in 2006(b)		5

Increase in taxes other than income	$	25


(a)		As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in tax expense was offset by a corresponding increase in revenues.

(b)		Represents the reduction of tax accruals in the second quarter of 2006 following settlements related to 2005 tax assessments.

Interest Expense, Net. The decrease in interest expense, net for the six months ended June 30, 2007 compared to the same period in 2006 was primarily due to scheduled principal payments on long-term debt owed to PECO Energy Transition Trust (PETT), partially offset by an increase in interest expense associated with higher outstanding long-term first mortgage bonds.

Other, Net. The increase for the six months ended June 30, 2007 compared to the same period in 2006 was primarily due to interest income associated with the adoption of FIN 48 and the PJM billing dispute settlement. See Note 14 of the Combined Notes to Consolidated Financial Statements for further details of the components of other, net. See Notes 3 and 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the adoption of FIN 48. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information on the PJM billing dispute settlement.

Income Taxes. The effective income tax rate was 35.1% for the six months ended June 30, 2007 compared to 33.3% for the six months ended June 30, 2006. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further details of the components of the effective income tax rates.

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PECO Electric Operating Statistics and Revenue Detail

PECO’s electric sales statistics and revenue detail were as follows:


	Six Months Ended June 30,
Retail Deliveries — (in GWhs)	2007		2006		Variance			% Change

Full service(a)
Residential		6,377		5,917		460			7.8	%
Small commercial & industrial		4,064		3,753		311			8.3	%
Large commercial & industrial		7,961		7,576		385			5.1	%
Public authorities & electric railroads		434		472		(38	)		(8.1	)%

Total full service		18,836		17,718		1,118			6.3	%

Delivery only(b)
Residential		21		32		(11	)		(34.4	)%
Small commercial & industrial		289		345		(56	)		(16.2	)%
Large commercial & industrial		7		29		(22	)		(75.9	)%

Total delivery only		317		406		(89	)		(21.9	)%

Total retail deliveries		19,153		18,124		1,029			5.7	%


(a)		Full service reflects deliveries to customers taking electric service under tariff rates.

(b)		Delivery only service reflects customers receiving electric generation service from a competitive electric generation supplier.


	Six Months Ended June 30,
Electric Revenue	2007		2006		Variance			% Change

Full service(a)
Residential	$	894	$	795	$	99			12.5	%
Small commercial & industrial		504		446		58			13.0	%
Large commercial & industrial		670		614		56			9.1	%
Public authorities & electric railroads		43		43		—			0.0	%

Total full service		2,111		1,898		213			11.2	%

Delivery only(b)
Residential		2		2		—			0.0	%
Small commercial & industrial		15		18		(3	)		(16.7	)%
Large commercial & industrial		—		1		(1	)		(100.0	)%

Total delivery only		17		21		(4	)		(19.0	)%

Total electric retail revenues		2,128		1,919		209			10.9	%

Other revenue(c)		131		118		13			11.0	%

Total electric and other revenue	$	2,259	$	2,037	$	222			10.9	%


(a)		Full service revenue reflects revenue from customers taking generation service under tariff rates, which include the cost of energy, the cost of transmission and distribution of the energy and a CTC.

(b)		Delivery only revenue reflects revenue from customers receiving generation service from a competitive electric generation supplier, which includes the cost of distribution of the energy and a CTC.

(c)		Other revenues include transmission revenue from PJM and other wholesale energy sales.

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PECO Gas Sales Statistics and Revenue Detail

PECO’s gas sales statistics and revenue detail were as follows:


	Six Months
	Ended
	June 30,
Deliveries to customers (in million cubic feet (mmcf))	2007		2006		Variance			% Change

Retail sales		37,285		31,213		6,072			19.5	%
Transportation		12,977		13,019		(42	)		(0.3	)%

Total		50,262		44,232		6,030			13.6	%


	Six Months
	Ended
	June 30,
Revenue	2007		2006		Variance			% Change

Retail sales	$	482	$	507	$	(25	)		(4.9	)%
Transportation		8		8		—			0.0	%
Resales and other		20		2		18			n.m.

Total gas revenue	$	510	$	517	$	(7	)		(1.4	)%

n.m. Not meaningful

Liquidity and Capital Resources

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings or, in the case of Generation and PECO, through capital contributions from Exelon when necessary. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, PECO have access to unsecured revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion, and $600 million, respectively, and ComEd has access to secured revolving credit facilities with aggregate bank commitments of $1 billion, that they currently utilize to support their commercial paper programs and to issue letters of credit. At June 30, 2007, ComEd has borrowed $475 million from its credit facility since its access to the commercial paper market is limited due to its current credit ratings. See the “Credit Matters” section below for further discussion. Exelon expects cash flows to be sufficient to meet operating, financing and capital expenditure requirements. See “Liquidity and Capital Resources” within Exelon’s 2006 Annual Report on Form 10-K for additional information.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. As a result of these factors, each of Exelon’s, ComEd and PECO’s working capital, defined as current assets less current liabilities, is in a net deficit position. ComEd intends to refinance maturing long-term debt and to repay a portion of its credit facility borrowings with long-term debt. As of June 30, 2007, ComEd has the capacity to issue up to approximately $460 million of additional first mortgage bonds subject to certain restrictions. To manage cash flows as more fully described below, ComEd did not pay a dividend in 2006 or during the six months ended June 30, 2007. Future acquisitions that Exelon may undertake may involve external debt financing or the issuance of additional Exelon common stock.

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downgraded credit ratings and due to under-recovery of energy costs, which have been recognized as a regulatory asset. Beginning in 2007, ComEd ceased earning margin on the energy component of its deliveries to its customers, nor is it collecting CTC revenues. While ComEd’s 2007 results reflect an $83 million annual rate increase as allowed by the ICC, this rate increase was based generally on 2004 costs and does not include the impacts of increased operating expenses since 2004 or additional net capital investment since the end of 2005. ComEd anticipates filing a new delivery service rate case during the third quarter of 2007 based on a 2006 test year and also filed a transmission rate case during the first quarter 2007. On June 5, 2007, FERC issued an order for the transmission rate case conditionally approving ComEd’s proposal to implement a formula based transmission rate effective May 1, 2007, subject to refund. The requested rate increase is designed to reduce the regulatory lag related to recovery of these costs and returns on ComEd’s investments. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion.

Cash Flows from Operating Activities

Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including ComEd and PECO. Generation’s future cash flows from operating activities will be affected by demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as make collections from customers. ComEd’s and PECO’s cash flows from operating activities primarily result from sales of electricity and, in the case of PECO, gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter of each fiscal year. ComEd’s and PECO’s future cash flows will be affected by the economy, weather, customer choice, existing and future regulatory proceedings relating to their revenues and their ability to achieve operating cost reductions. See Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

Operating cash flows could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder the ability of PECO to fund its business requirements. Beginning in 2007, ComEd began purchasing electricity through the ICC authorized reverse-auction process in order to meet the retail electricity needs of ComEd’s customers because ComEd does not own any generation. If the price at which ComEd is allowed to sell electricity is below ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd and, possibly, Exelon. However, the Proposed Legislation introduced in the State of Illinois in July 2007 in connection with the Settlement has significantly reduced the probability of rate freeze legislation and other legislative actions proposed in previous periods. If enacted, the Proposed Legislation should provide ComEd with greater stability and certainty that it will be able to procure electricity and pass through the costs of that electricity to its customers. Additionally, ComEd has implemented a voluntary “cap and deferral” program to mitigate the impact on its residential customers of transitioning to the post rate freeze period. ComEd’s cash flows from operations will be reduced in the first years of the program, but will increase as any deferred amounts are collected with a 3.25% return on any deferred balances. As of June 30, 2007, approximately 36,000 or 1% of ComEd’s residential customers have enrolled in the program. ComEd has also implemented various other programs to assist its residential customers, including a $64 million rate relief package and other initiatives. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion of ComEd’s procurement case, residential rate stabilization program and rate relief efforts.

Beginning in 2007, Generation’s sales to counterparties other than ComEd and PECO increased due to the expiration of the PPA with ComEd on December 31, 2006. These incremental bilateral contracts are subject to the credit risk associated with the ability of counterparties to meet their contractual payment obligations to Generation. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. When Generation sells power, as market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To the extent Generation does not have enough collateral to cover its risk of payment collection, Generation’s revenues are at risk. With respect to Generation’s sales, when market prices decrease there is a corresponding increase in Generation’s revenues at risk.

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Beginning in 2007, under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, collateral postings will be one-sided from Generation only. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren, as the case may be, is not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation is required to post collateral. To the extent Ameren or ComEd do not or cannot pay Generation under the supplier forward contracts, Generation is therefore exposed. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information regarding Generation’s collateral policy.

Additionally, Exelon, through ComEd, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. In November 2006, ComEd received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its position that proceeds from the fossil plant sales resulted from an “involuntary conversion.” This potential tax obligation is significant and an adverse determination could require a significant payment. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion regarding ComEd’s tax position on the 1999 sale of its fossil generating assets.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the six months ended June 30, 2007 and 2006:


	Six Months
	Ended
	June 30,
	2007			2006			Variance

Net income	$	1,393		$	1,044		$	349
Add (subtract):
Non-cash operating activities(a)		1,427			1,151			276
Income taxes		87			300			(213	)
Changes in working capital and other noncurrent assets and liabilities(b)		(1,241	)		(277	)		(964	)
Pension and non-pension postretirement benefit contributions		(40	)		(30	)		(10	)

Net cash flows provided by operations	$	1,626		$	2,188		$	(562	)


(a)		Represents depreciation, amortization and accretion, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, other decommissioning-related activities, stock compensation expense and other non-cash charges.

(b)		Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

Cash flows provided by operations for the six months ended June 30, 2007 and 2006 by registrant were as follows:


	Six Months
	Ended
	June 30,
	2007		2006

Exelon	$	1,626	$	2,188
Generation		1,115		1,067
ComEd		184		552
PECO		467		550

Changes in Exelon’s, Generation’s, ComEd’s and PECO’s cash flows from operations were generally consistent with changes in respective results of operations, as adjusted by changes in working capital in the

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normal course of business. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 2007 and 2006 were as follows:

Generation


	•	At June 30, 2007 and December 31, 2006, Generation had accounts receivable from ComEd of $68 million under its supplier forward agreement and $197 million under the PPA, which expired on December 31, 2006, respectively. The decrease was primarily due to lower revenues resulting from the expiration of the PPA with ComEd as well as ComEd making semi-monthly payments under its supplier forward contracts in 2007 as opposed to making monthly payments in 2006. At June 30, 2006 and December 31, 2005, Generation had accounts receivable from ComEd under the PPA of $247 million and $242 million, respectively.

	•	At June 30, 2007 and December 31, 2006, Generation had accounts receivable from PECO under the PPA of $146 million and $153 million, respectively. At June 30, 2006 and December 31, 2005, Generation had accounts receivable from PECO under the PPA of $170 million and $151 million, respectively.

	•	During the six months ended June 30, 2007 and 2006, Generation had net disbursements of counterparty collateral of $498 million and net collections of counterparty collateral of $183 million, respectively. The decrease in cash flows was primarily due to changes in collateral requirements resulting from increased activity within exchange-based markets for energy and fossil fuel.

	•	In 2005, Exelon received a $102 million Federal income tax refund for capital losses generated in 2003 related to Generation’s previously owned investment in Sithe, which were carried back to prior periods. In the first quarter of 2006, Exelon remitted a $98 million payment to the IRS in connection with the settlement of the IRS’s challenge of the timing of the above-described deduction. This payment included $6 million of interest, which was recognized as interest expense in the first quarter of 2006.

ComEd


	•	As a result of ComEd’s downgraded credit ratings, ComEd is making accelerated semi-monthly payments under its supplier forward contracts with its energy suppliers, including Generation. Prior to the credit ratings downgrade, ComEd made monthly payments to its energy suppliers. At June 30, 2007 and December 31, 2006, ComEd had accrued payments to Generation for energy purchases of $68 million and $197 million, respectively. At June 30, 2006 and December 31, 2005, ComEd had accrued payments to Generation for energy purchases of $247 million and $242 million, respectively. At June 30, 2007 and December 31, 2006, ComEd had accrued payments to other energy suppliers of $68 million and $10 million, respectively. At June 30, 2006 and December 31, 2005, ComEd had accrued payments to other energy suppliers of $3 million and $12 million, respectively.

	•	During the six months ended June 30, 2007, ComEd had net under-recovered energy costs of $104 million. See Note 5 of the Combined Notes to the Consolidated Financial Statements for more information.

	•	During the six months ended June 30, 2007, ComEd’s revenue exceeded its cash collections from customers by $38 million. During the six months ended June 30, 2006, ComEd’s cash collections exceeded its revenue to customers by $24 million.

	•	As part of its Rate Relief programs, ComEd has deposited $39 million into an escrow account classified as restricted cash. As ComEd issues credits to customers and funds various customer programs, ComEd will request reimbursements from the escrow account. See Note 5 of the Combined Notes to the Consolidated Financial Statements for more information on the Rate Relief Programs.

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Cash Flows from Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2007 and 2006 by registrant were as follows:


	Six Months
	Ended
	June 30,
	2007			2006

Exelon	$	(1,367	)	$	(1,360	)
Generation		(584	)		(666	)
ComEd		(549	)		(461	)
PECO		(160	)		(157	)

Capital expenditures by registrant and business segment for the six months ended June 30, 2007 and projected amounts for the twelve months ended December 31, 2007 are as follows:


	Six Months
	Ended		Projected
	June 30, 2007		2007

Generation	$	550	$	1,353
ComEd		559		1,055
PECO		161		355
Other(a)		14		38

Total Exelon capital expenditures	$	1,284	$	2,801


(a)		Other includes corporate operations and shared service entities, including BSC.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation. Generation’s capital expenditures for 2007 reflect additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.

ComEd and PECO. Approximately 50% of the projected 2007 capital expenditures at ComEd and PECO are for continuing projects to maintain and improve the reliability of their transmission and distribution systems. The remaining amounts are for capital additions to support new business and customer growth. ComEd and PECO are each continuing to evaluate their own total capital spending requirements. ComEd and PECO anticipate that they will fund their own capital expenditures by internally generated funds, borrowings and the issuance of debt or preferred securities.

Other significant investing activities of the Registrants for the six months ended June 30, 2007 and 2006 were as follows:

Exelon


	•	Exelon contributed $49 million and $53 million to its investments in synthetic fuel-producing facilities during the six months ended June 30, 2007 and 2006, respectively.

Generation


	•	As a result of its prior contributions to the Exelon intercompany money pool, $13 million was returned to Generation during the six months ended June 30, 2007.

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	•	On February 9, 2007, Tamuin International Inc., 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.

	•	Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of SCEP, a 350-megawatt natural gas-fired, peaking electric power plant located in Chicago, Illinois, which began operation in 2002. In 2002, Generation and Peoples Calumet owned 70% and 30%, respectively, of SCEP. Generation reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a 20-year period. On March 31, 2006, Generation entered into an agreement to accelerate the acquisition of Peoples Calumet’s interest in SCEP. This transaction closed on May 31, 2006. Under the agreement, Generation paid Peoples Calumet approximately $47 million for its remaining interest in SCEP. Generation financed this transaction using short-term debt and available cash.

PECO


	•	As a result of its prior contributions to the Exelon intercompany money pool, $8 million was returned to PECO during the six months ended June 30, 2006.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the six months ended June 30, 2007 and 2006 by Registrant were as follows:


	Six Months Ended
	June 30,
	2007			2006

Exelon	$	(348	)	$	(686	)
Generation		(625	)		(411	)
ComEd		375			(95	)
PECO		(306	)		(405	)

Debt. On January 15, 2007, ComEd repaid at maturity $145 million of its 7.625% notes.

On March 22, 2007, ComEd issued an additional $300 million aggregate principal amount of the same series as ComEd’s currently outstanding First Mortgage 5.90% Bonds, Series 103, due March 15, 2036. The proceeds of the bonds were used to refinance outstanding commercial paper and to repay a portion of borrowings under its revolving credit facility.

On March 19, 2007, PECO issued $175 million aggregate principal amount of its First and Refunding Mortgage Bonds, 5.70% Series due 2037. The proceeds of the bonds were used to supplement working capital previously financed through sales of commercial paper and for other general corporate purposes.

On March 6, 2006, ComEd issued $325 million aggregate principal amount of its First Mortgage 5.90% Bonds, Series 103, due March 15, 2036. The proceeds of the bonds were used to supplement working capital, which previously refinanced amounts that ComEd used to repay bonds and notes.

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen their respective balance sheets.

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Dividends. Cash dividend payments and distributions during the six months ended June 30, 2007 and 2006 by registrant were as follows:


	Six Months Ended
	June 30,
	2007		2006

Exelon	$	592	$	535
Generation		665		322
PECO		278		253

Exelon paid dividends of $296 million and $296 million on March 10, 2007 and June 11, 2007, respectively, to shareholders of record at the close of business on February 15, 2007 and May 15, 2007, respectively. On July 24, 2007, Exelon’s board of directors declared a quarterly dividend of $0.44 per share on Exelon’s common stock, which is payable on September 10, 2007 to shareholders of record at the end of the day on August 15, 2007. Exelon paid dividends of $267 million and $268 million on March 10, 2006 and June 12, 2006, respectively, to shareholders of record at the close of business on February 15, 2006 and May 15, 2006, respectively. See “Dividends” section of ITEM 5 of Exelon’s 2006 Annual Report on Form 10-K for a further discussion of Exelon’s dividend policy.

During 2006 and the six months ended June 30, 2007, ComEd did not pay any dividend. The decision by the ComEd Board of Directors not to declare a dividend during 2006 and 2007 was the result of several factors, including ComEd’s need for a rate increase to cover existing costs and anticipated levels of future capital expenditures as well as the continued uncertainty related to ComEd’s regulatory filings as discussed in Note 5 of the Combined Notes to Consolidated Financial Statements. ComEd’s Board of Directors will assess ComEd’s ability to pay a dividend after 2007.

Intercompany Money Pool. Generation repaid borrowings from the Exelon intercompany money pool totaling $92 million during the six months ended June 30, 2006. During the six months ended June 30, 2006, ComEd repaid $140 million that it had borrowed from the Exelon intercompany money pool. As of January 10, 2006, ComEd suspended its participation in the money pool. During the six months ended June 30, 2007, PECO repaid $45 million that it had borrowed from the Exelon intercompany money pool.

Short-Term Borrowings. During the six months ended June 30, 2007, Exelon, Generation, ComEd and PECO issued (repaid) $(127) million, $39 million, $(60) million and $27 million of commercial paper, respectively. During the six months ended June 30, 2006, Exelon, Generation, ComEd and PECO issued (repaid) $(106) million, $(2) million, $(120) million and $7 million of commercial paper, respectively. At June 30, 2007, ComEd had $475 million of outstanding borrowings under its credit agreement.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during the six months ended June 30, 2007 and 2006 by registrant was as follows:


	Six Months Ended
	June 30,
	2007		2006

Exelon	$	534	$	422
ComEd		180		174
PECO		354		248

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Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during the six months ended June 30, 2007, and 2006 by registrant were as follows:


	Six Months
	Ended
	June 30,
	2007		2006

Generation	$	—	$	5
ComEd		—		23
PECO		165		83

Other. Other significant financing activities for Exelon for the six months ended June 30, 2007 and 2006 were as follows:


	•	Exelon purchased treasury shares totaling $37 million and $53 million during the six months ended June 30, 2007 and 2006, respectively.

	•	Exelon received proceeds from employee stock plans of $145 million and $107 million during the six months ended June 30, 2007 and 2006, respectively.

	•	There were $55 million and $29 million of excess tax benefits included as a cash inflow in other financing activities during the six months ended June 30, 2007 and 2006, respectively.

Credit Matters

Credit Facilities. Exelon, Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and ComEd meets its short-term liquidity requirements primarily through borrowings from its credit facility. The Registrants may use credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. At June 30, 2007, ComEd had $475 million of outstanding borrowings under its credit agreement. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

At June 30, 2007, the Registrants had the following bank commitments and available capacity under the various credit agreements to which they are a party and the indicated amounts of outstanding commercial paper:


	Aggregate Bank		Available		Outstanding
Borrower	Commitment(a)		Capacity(b)		Commercial Paper

Exelon	$	1,000	$	993	$	17
Generation		5,000		4,879		39
ComEd		1,000		455		—
PECO		600		598		122


(a)		Represents the total bank commitments to the borrower under credit agreements to which the borrower is a party.

(b)		Available capacity represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and any required reserves. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. In the cases of Exelon, Generation and PECO, the maximum LIBOR adder is 65 basis points, and in the case of ComEd, it is 200 basis points.

The average interest rates on commercial paper for the six months ended June 30, 2007 for Exelon, Generation, ComEd and PECO were approximately 5.34%, 5.34%, 5.58% and 5.35%, respectively.

The credit agreements require the Registrants to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The

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following table summarizes the minimum thresholds reflected in the credit agreements for the six-month period ended June 30, 2007:

Exelon

Generation

ComEd

PECO

Credit agreement threshold

2.50 to 1

3.00 to 1

2.25 to 1

2.00 to 1

At June 30, 2007, the Registrants were in compliance with the foregoing thresholds.

The ComEd credit agreement imposes a restriction on future mortgage bond issuances by ComEd. It requires ComEd to maintain at least $1.75 billion of issuance availability (ignoring any interest coverage test) in the form of “property additions” or “bondable bond retirements” (previously issued, but now retired, bonds), most of which are required to be maintained in the form of “bondable bond retirements.” In general, a dollar of bonds can be issued under ComEd’s Mortgage on the basis of $1.50 of “property additions”, subject to an interest coverage test, or $1 of “bondable bond retirements”, which may or may not be subject to an interest coverage test. As of June 30, 2007, ComEd was in compliance with this requirement.

Intercompany Money Pool. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. As of January 10, 2006, ComEd suspended its participation in the money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the six months ended June 30, 2007 are presented in the following table in addition to the net contribution or borrowing as of June 30, 2007:


					June 30,
					2007
	Maximum		Maximum		Contributed
	Contributed		Borrowed		(Borrowed)

Generation	$	314	$	87	$	—
PECO		60		207		—
BSC		87		165		(4	)
Exelon		56		N/A		4

Security Ratings. The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets.

On March 9, 2007, Fitch Ratings (Fitch) downgraded the debt ratings of ComEd’s senior secured debt, senior unsecured debt and commercial paper. The ratings remain on Ratings Watch Negative. The rating action reflects Fitch’s concerns regarding the continued legislative efforts to freeze rates and the prospects for adequate and timely cost recovery through future rate increases.

On March 26, 2007, Moody’s Investor Service (Moody’s) downgraded ComEd’s senior unsecured debt and commercial paper due to continued regulatory and political uncertainty in Illinois. ComEd’s long-term debt ratings remain under review for a possible downgrade.

On June 1, 2007, Standard & Poor’s Corporation (S&P) downgraded ComEd’s short-term and long-term security ratings due to the continued regulatory and political uncertainty encountered by ComEd. ComEd’s ratings remain on CreditWatch with negative implications.

Listed below are ComEd’s current securities ratings resulting from the latest rating actions.

ComEd Security Ratings

Fitch

Moody’s

S&P

Senior secured debt

BBB

Baa2

BBB-

Senior unsecured debt

BB+

Ba1

B+

Commercial paper

Not prime

On June 12, 2007, PECO’s commercial paper rating from Fitch was changed to F2 from F1. According to Fitch, the ratings “... do not reflect any deterioration of PECO’s liquidity profile”; rather, they reflect a change to Fitch’s short-term and long-term rating linkage practices.

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The securities ratings and outlook for Exelon and Generation have not changed from those set forth in Exelon’s 2006 Annual Report on Form 10-K.

None of the Registrants’ borrowings are subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under the Registrants’ credit agreements.

A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on its net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation’s situation at the time of the demand. If Exelon can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

Shelf Registrations

As of June 30, 2007, Exelon, PECO and ComEd had current shelf registration statements for the sale of $300 million, $75 million and an unspecified amount, respectively, of securities that were effective with the SEC. Exelon and ComEd are well-known seasoned issuers as described by the SEC and may file automatic shelf registration statements that are not required to specify the amount of securities to be offered thereon. Although Exelon is a well-known seasoned issuer, Exelon has not filed an automatic shelf registration statement with the SEC. The ability of Exelon, ComEd or PECO to sell securities in the public market or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.

Investments in Synthetic Fuel-Producing Facilities

Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. Section 45K (formerly Section 29) of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45K contains a provision under which credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds.

The following table (in dollars) provides the estimated phase-out range for 2007 based on the per barrel price of oil as of June 30, 2007. The table also contains the estimated 2007 annual average New York Mercantile Exchange, Inc. index (NYMEX) prices per barrel at June 30, 2007 based on year-to-date and futures prices.


	Estimated 2007

Beginning of Phase-Out Range(a)	$	62
End of Phase-Out Range(a)		78
2007 Annual Average NYMEX		66


(a)		The estimated 2007 phase-out range as of June 30, 2007 is based upon the actual 2006 phase-out range. The actual 2006 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2007. The actual 2006 phase-out range was increased by 2% (Exelon’s estimate of inflation) to arrive at the estimated 2007 phase-out range.

As of June 30, 2007, Exelon has estimated the 2007 phase-out to be 25%, which has reduced Exelon’s earned after-tax credits of $139 million to $105 million for the six months ended June 30, 2007. Exelon anticipates

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generating approximately $210 million of cash over the life of these investments, of which approximately $80 million is expected in total for 2007 and 2008, assuming a 25% phase-out of tax credits. This estimate may change significantly due to the volatility of oil prices. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion.

Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. The Registrants’ contractual obligations and commercial commitments as of June 30, 2007 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2006 Annual Report on Form 10-K except for the following:

Exelon


	•	Letters of credit increased $42 million and guarantees increased by $209 million primarily as a result of leasing activities, energy trading and performance guarantees.

	•	Exelon adopted FIN 48 as of January 1, 2007. As of the date of adoption, Exelon’s FIN 48 liability was $501 million and FIN 48 net interest payable was $130 million. As of June 30, 2007, Exelon’s FIN 48 liability was $487 million and FIN 48 net interest payable was $141 million. The FIN 48 interest payable was calculated based on Exelon’s net FIN 48 position at January 1, 2007 and June 30, 2007. As of June 30, 2007, Exelon was unable to reasonably estimate the timing of FIN 48 liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

Generation


	•	Letters of credit increased by $41 million and guarantees increased by $176 million primarily as a result of Generation’s energy trading activities and the performance guaranty agreement entered into in connection with the sale of TEG and TEP.

	•	Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others decreased by approximately $760 million during the six months ended June 30, 2007, reflecting increases of approximately $819 million, $495 million and $124 million in 2008, 2009 and 2010 sales commitments, respectively, offset by the fulfillment of approximately $2,198 million of 2007 commitments during the six months ended June 30, 2007. The increases were primarily due to increased forward sales of energy to counterparties other than ComEd as a result of the expiration of the PPA with ComEd on December 31, 2006 (see Note 5 of the Combined Notes to Consolidated Financial Statements for further information), as well as increased overall hedging activity in the normal course of business.

	•	Generation’s long-term commitments for nuclear fuel as of June 30, 2007 increased by $17 million, $72 million, $93 million, $102 million, and $293 million for 2008, 2009, 2010, 2011, 2012 and beyond, respectively, as compared to December 31, 2006. Generation’s long-term commitments for coal as of June 30, 2007 increased by $91 million, $48 million and $2 million for 2008, 2009 and 2010, respectively, as compared to December 31, 2006. Increases in nuclear fuel and coal commitments are due to contracts entered into in the normal course of business.

	•	Generation adopted FIN 48 as of January 1, 2007. As of the date of adoption, Generation’s FIN 48 liability was $38 million and FIN 48 net interest receivable was $1 million. As of June 30, 2007, Generation’s FIN 48 liability was $41 million and FIN 48 net interest receivable was $1 million. The FIN 48 interest receivable was calculated based on Generation’s net FIN 48 position at January 1, 2007 and June 30, 2007. As of June 30, 2007, Generation was unable to reasonably estimate the timing of FIN 48 liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

ComEd


	•	ComEd issued $300 million First Mortgage 5.90% Bonds due March 15, 2036.

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	•	ComEd adopted FIN 48 as of January 1, 2007. As of the date of adoption, ComEd’s FIN 48 liability was $427 million and FIN 48 net interest payable was $167 million. As of June 30, 2007, ComEd’s FIN 48 liability was $415 million and FIN 48 net interest payable was $184 million. The FIN 48 interest payable was calculated based on ComEd’s net FIN 48 position at January 1, 2007 and June 30, 2007. As of June 30, 2007, ComEd was unable to reasonably estimate the timing of FIN 48 liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

PECO


	•	PECO issued $175 million First and Refunding Mortgage Bonds, 5.70% Series due March 15, 2037.

	•	PECO’s total fuel purchase obligations increased by approximately $134 million during the six months ended June 30, 2007, reflecting an increase of $18 million, $63 million, $34 million and $19 million in 2007, 2008, 2009 and 2010, respectively, primarily related to the purchase of natural gas and related transportation services.

	•	PECO adopted FIN 48 as of January 1, 2007. As of the date of adoption, PECO’s FIN 48 liability was $11 million and FIN 48 net interest receivable was $21 million. As of June 30, 2007, PECO’s FIN 48 liability was $2 million and FIN 48 net interest receivable was $27 million. The FIN 48 interest receivable was calculated based on PECO’s net FIN 48 position at January 1, 2007 and June 30, 2007. As of June 30, 2007, PECO was unable to reasonably estimate the timing of FIN 48 liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

See Note 13 of Combined Notes to Consolidated Financial Statements for further information on the Registrants’ commitments.

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EXELON GENERATION COMPANY

General

Generation operates in a single business segment and its operations consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to Generation’s results of operations for the three months ended June 30, 2007 compared to three months ended June 30, 2006 and six months ended June 30, 2007 compared to the six months ended June 30, 2006 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to revolving credit facilities that Generation currently utilizes to support its commercial paper program and to issue letters of credit. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

Cash Flows from Operating Activities

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Cash Flows from Financing Activities

A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to Generation’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to Generation’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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COMMONWEALTH EDISON COMPANY

General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services in northern Illinois, including the City of Chicago.

Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to ComEd’s results of operations for the three months ended June 30, 2007 compared to three months ended June 30, 2006 and six months ended June 30, 2007 compared to the six months ended June 30, 2006 is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At June 30, 2007, ComEd has borrowed $475 million from its secured credit facility since its access to the commercial paper market is limited due to its current credit ratings. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. As a result of these factors, ComEd’s working capital, defined as current assets less current liabilities, is in a net deficit position. ComEd intends to refinance maturing long-term debt and to repay a portion of its credit facility borrowings with long-term debt. As of June 30, 2007, ComEd has the capacity to issue up to approximately $460 million of additional first mortgage bonds subject to certain restrictions. To manage cash flows, ComEd did not pay a dividend in 2006 or during the six months ended June 30, 2007.

During the six months ended June 30, 2007 as compared to the same period in 2006, ComEd experienced a decrease in operating cash flows primarily due to a change in its payment terms with energy suppliers resulting from downgraded credit ratings and due to under-recovery of energy costs, which have been recognized as a regulatory asset. Beginning in 2007, ComEd ceased earning margin on the energy component of its deliveries to its customers, nor is it collecting CTC revenues. While ComEd’s 2007 results reflect an $83 million annual rate increase as allowed by the ICC, this rate increase was based generally on 2004 costs and does not include the impacts of increased operating expenses since 2004 or additional net capital investment since the end of 2005. ComEd anticipates filing a new delivery service rate case during the third quarter of 2007 based on a 2006 test year and also filed a transmission rate case during the first quarter of 2007. On June 5, 2007, FERC issued an order for the transmission rate case conditionally approving ComEd’s proposal to implement a formula based transmission rate effective May 1, 2007, subject to refund. The requested rate increase is designed to reduce the regulatory lag related to recovery of these costs and returns on ComEd’s investments. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion.

Cash Flows from Operating Activities

A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Cash Flows from Investing Activities

A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to ComEd’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to ComEd’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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PECO ENERGY COMPANY

General

PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

Executive Overview

A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to PECO’s results of operations for the three months ended June 30, 2007 compared to three months ended June 30, 2006 and six months ended June 30, 2007 compared to six months ended June 30, 2006 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to revolving credit facilities that PECO currently utilizes to support its commercial paper program. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans.

Cash Flows from Operating Activities

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s Risk Oversight Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Risk Oversight Committee is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The Risk Oversight Committee reports to the Exelon Board of Directors on the scope of the risk management activities.

Commodity Price Risk (Exelon, Generation and ComEd)

To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather, governmental regulatory and environmental policies, and other factors. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal and emission allowances. Within Exelon, Generation has the most exposure to commodity price risk. PECO has transferred most of its commodity price risk to Generation through a PPA that expires at the end of 2010. ComEd has transferred most of its near term commodity price risk to generating companies through the Illinois auction process.

Exelon and Generation

In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of the exposure to a phase-out of the tax credits for the sale of synthetic fuel produced from coal. One of the sellers of the tax credits has security interests in these derivatives. Including the related mark-to-market gains and losses on these derivatives, interests in synthetic fuel-producing facilities increased Exelon’s net income by $27 million and reduced Exelon’s net income by $55 million during the three months ended June 30, 2007 and 2006, respectively. Additionally, interests in synthetic fuel-producing facilities increased net income by $52 million and reduced net income by $43 million during the six months ended June 30, 2007 and 2006, respectively. Exelon anticipates that it will continue to record income or losses related to the mark-to-market gains or losses on its derivative instruments and changes to the tax credits earned by Exelon during the period of production due to the volatility of oil prices. Net income from interests in synthetic fuel-producing facilities is reflected in Exelon’s Consolidated Statements of Operations within income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and other, net. See Note 10 of the Combined Notes to Consolidated Financial Statements for further information related to synthetic fuel activity.

Generation

Generation’s energy contracts are accounted for under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Economic hedges may qualify for the normal purchases and normal sales exemption to SFAS No. 133, which is discussed in Critical Accounting Policies and Estimates within Exelon’s 2006 Annual Report on Form 10-K. Energy contracts that do not qualify for the normal purchases and normal sales exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and the derivatives are designated as cash-flow hedges, in which case changes in fair value are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 or are not designated as such are recognized in current earnings.

Normal Operations and Hedging Activities. Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’s retail loads, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as financial derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. The maximum length of time over which cash flows

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related to energy commodities are currently being hedged is approximately three years. Generation has estimated a greater than 90% economic hedge ratio for 2007, which includes cash flow and other derivatives, for its energy marketing portfolio. This economic hedge ratio represents the percentage of its forecasted aggregate annual economic generation supply that is committed to firm sales, including sales to ComEd’s and PECO’s retail load. ComEd’s and PECO’s retail loads assumptions are based on forecasted average demand. A portion of Generation’s economic hedge may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. The economic hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods, Generation’s amount hedged declines to meet its energy and capacity commitments to ComEd and PECO. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price exposure for Generation’s economic hedge portfolio associated with a 10% reduction in the annual average around-the-clock market price of electricity would be a decrease of less than $50 million in net income. This sensitivity assumes that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

Proprietary Trading Activities. Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities, which included volumes of 4,775 GWhs and 7,769 GWhs for the three months ended June 30, 2007 and 2006, respectively, and 9,876 GWhs and 14,754 GWhs for the six months ended June 30, 2007 and 2006, respectively are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s revenue from energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of Generation’s owned and contracted supply of electricity. Generation expects this level of proprietary trading activity to continue in the future. Trading portfolio activity for the six months ended June 30, 2007 resulted in a gain of $32 million due to a net mark-to-market gain of $28 million and realized gain of $4 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its Value-at-Risk (VaR). The daily VaR on proprietary trading activity averaged $160,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the six months ended June 30, 2007 of $3,306 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and VaR limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s Risk Oversight Committee monitor the financial risks of the proprietary trading activities.

Trading and Economic Hedge Marketing Activities. The following detailed presentation of the trading and economic hedge marketing activities at Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2007 to June 30, 2007. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from accumulated OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets.


	Total

Total mark-to-market energy contract net assets at January 1, 2007	$	499
Total change in fair value during 2007 of contracts recorded in earnings		(49	)
Reclassification to realized at settlement of contracts recorded in earnings		(55	)
Reclassification to realized at settlement from accumulated OCI		(31	)
Effective portion of changes in fair value — recorded in OCI		(331	)

Total mark-to-market energy contract net assets at June 30, 2007	$	33

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The following table details the balance sheet classification of Generation’s mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2007 and December 31, 2006:


	June 30,			December 31,
	2007			2006

Current assets	$	749		$	1,408
Noncurrent assets		210			171

Total mark-to-market energy contract assets		959			1,579

Current liabilities		(628	)		(1,003	)
Noncurrent liabilities		(298	)		(77	)

Total mark-to-market energy contract liabilities		(926	)		(1,080	)

Total mark-to-market energy contract net assets	$	33		$	499

The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask mid-point prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets, which are primarily option contracts, represents contracts for which external valuations are not available. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of June 30, 2007 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts Generation holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation’s total mark-to-market asset or liability. Second, this table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.


	Maturities Within
															2012 and		Total Fair
	2007			2008			2009			2010			2011		Beyond		Value

Normal Operations, qualifying cash-flow hedge contracts(a):
Prices provided by external sources	$	128		$	(1	)	$	(66	)	$	(8	)	$	—	$	—	$	53

Normal Operations, other derivative contracts(b):
Actively quoted prices	$	(81	)	$	2		$	(19	)	$	—		$	—	$	—	$	(98	)
Prices provided by external sources		92			(9	)		4			—			—		—		87
Prices based on model or other valuation methods		7			(6	)		(10	)		—			—		—		(9	)

Total	$	18		$	(13	)	$	(25	)	$	—		$	—	$	—	$	(20	)


(a)		Mark-to-market gains and losses on economic hedge contracts that qualify as cash-flow hedges are recorded in OCI.

(b)		Mark-to-market gains and losses on other economic hedge and trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

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The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of June 30, 2007. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of accumulated OCI related to cash-flow hedges from January 1, 2007 to June 30, 2007, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.


	Total Cash-Flow Hedge OCI Activity,
	Net of Income Tax
	Power Team Normal			Interest-Rate			Total
	Operations and			and Other			Cash-Flow
	Hedging Activities			Hedges			Hedges

Accumulated OCI derivative gain (loss) at January 1, 2007	$	250		$	(3	)	$	247
Changes in fair value		(200	)		3			(197	)
Reclassifications from accumulated OCI to net income		(17	)		—			(17	)

Accumulated OCI derivative gain at June 30, 2007	$	33		$	—		$	33

ComEd

ComEd has derivatives to manage its market price exposures to certain wholesale contracts. Additionally, the supplier forward contracts that ComEd has entered into as part of the initial ComEd auction (see Note 5 of the Combined Notes to Consolidated Financial Statements) are deemed to be derivatives that qualify for the normal purchases and normal sales exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes. As of June 30, 2007, the fair value of the derivative wholesale contracts of $5 million was recorded on ComEd’s Consolidated Balance Sheet as a current liability.

ComEd has transferred most of its near term commodity price risk to generating companies through the Illinois auction process.

Credit Risk (Exelon, Generation, ComEd and PECO)

Generation

Generation’s PPA with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren procurement auctions. Beginning in 2007 and as a result of the auctions, Generation’s sales to counterparties other than ComEd and PECO increased due to the expiration of the PPA with ComEd on December 31, 2006. Although the Proposed Legislation will establish a new procurement process in place of the procurement auctions, Generation is expected to participate in the alternative competitive procurement process and will continue to have credit risk in connection with contract for sale of electricity resulting from the alternative competitive procurement process. Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment; therefore, Generation’s credit risk profile has changed based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren.

Generation attempts to enter 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 allows for cross product netting. In addition to payment netting language in the enabling agreement, the credit department establishes credit limits and letter of credit requirements for each counterparty, which are defined in each contract. 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

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extent that a counterparty’s credit limit and letter of credit thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. The 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, net of collateral, as of June 30, 2007. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) which are discussed below.


	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of June 30, 2007(a)	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure

Investment grade	$	875	$	19	$	856		2	$	194
Non-investment grade		7		—		7		—		—
No external ratings
Internally rated — investment grade		5		1		4		—		—
Internally rated — non-investment grade		5		2		3		—		—

Total	$	892	$	22	$	870		2	$	194


(a)		This table does not include accounts receivable exposure and credit risk exposure from retail energy sales or uranium procurement contracts.


	Maturity of Credit Risk Exposure
					Exposure		Total Exposure
	Less than				Greater than		Before Credit
Rating as of June 30, 2007(a)	2 Years		2-5 Years		5 Years		Collateral

Investment grade	$	843	$	32	$	—	$	875
Non-investment grade		6		1		—		7
No external ratings
Internally rated — investment grade		5		—		—		5
Internally rated — non-investment grade		4		1		—		5

Total	$	858	$	34	$	—	$	892


(a)		This table does not include accounts receivable exposure and credit risk exposure from retail energy sales or uranium procurement contracts.

Collateral. As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

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Generation sells output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. Beginning in 2007, under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, collateral postings will be one-sided from Generation only. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, neither ComEd nor Ameren is required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation may be required to post collateral. See Note 4 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2006 Annual Report on Form 10-K for further information on contracted clearing prices related to the ComEd and Ameren auctions.

As of June 30, 2007, Generation had $257 million of collateral deposit payments being held by counterparties and Generation was holding $6 million of collateral deposits received from counterparties.

RTOs and ISOs. Generation participates in the following established, real-time energy markets that are administered by: PJM, ISO-NE, New York ISO, MISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation’s financial condition, results of operations or net cash flows.

Fuel Procurement. Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term contracts for uranium concentrates, and long-term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Non-performance by these counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position.

ComEd and PECO

Credit risk for ComEd and PECO is managed by credit and collection policies which are consistent with state regulatory requirements. ComEd and PECO are each currently obligated to provide service to all electric customers within their respective franchised territories. ComEd and PECO record a provision for uncollectible accounts, based upon historical experience and third-party studies, to provide for the potential loss from nonpayment by these customers. ComEd will continue to monitor the impact of the reverse-auction power prices on its customer payment practices as it relates to its provision for uncollectible accounts. ComEd will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. ComEd has reduced the number of customer disconnections for nonpayment. ComEd will monitor the impact of its disconnection practices and will make any necessary adjustments to the provision for uncollectible accounts. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in PAPUC regulations.

Under Pennsylvania’s Competition Act, licensed entities, including competitive electric generation suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO’s retail electric service territory. Currently, there are no third parties providing billing of PECO’s charges to customers or advanced metering; however, if this occurs, PECO would be subject to credit risk related to the ability of the third parties to collect such receivables from the customers.

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Exelon

Exelon’s Consolidated Balance Sheet as of June 30, 2007 included a $541 million net investment in direct financing leases. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1,492 million, less unearned income of $951 million. The future minimum lease payments are supported by collateral and credit enhancement measures, including letters of credit, surety bonds and credit swaps issued by high credit quality financial institutions. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases.

Interest-Rate Risk (Exelon, Generation, ComEd and PECO)

Variable Rate Debt. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants may also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital. At June 30, 2007, Exelon had $100 million of notional amounts of fair-value hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a $1 million decrease in Exelon’s pre-tax earnings for the three months ended June 30, 2007. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a decrease of less than $1 million for Generation, ComEd and PECO in pre-tax earnings for the three months ended June 30, 2007.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of June 30, 2007, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $496 million reduction in the fair value of the trust assets.

Exelon and Generation maintain trust assets associated with defined benefit pension and other postretirement benefits. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Policies and Estimates section within Exelon’s 2006 Annual Report on Form 10-K for information regarding the pension and other postretirement benefit trust assets.

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Item 4.	Controls and Procedures

During the second quarter of 2007, Exelon’s management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by Exelon to ensure that (a) material information relating to Exelon, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of Exelon and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2007, the principal executive officer and principal financial officer of Exelon concluded that Exelon’s disclosure controls and procedures were effective to accomplish its objectives. Exelon continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2007 that have materially affected, or are reasonably likely to materially affect, Exelon’s internal control over financial reporting.

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Item 4T.	Controls and Procedures

During the second quarter of 2007, each of Generation’s, ComEd’s and PECO’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by Generation, ComEd and PECO to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2007, the principal executive officer and principal financial officer of Generation, ComEd and PECO concluded that such registrant’s disclosure controls and procedures were effective to accomplish its objectives. Generation, ComEd and PECO each continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2007 that have materially affected, or are reasonably likely to materially affect, each of Generation’s, ComEd’s and PECO’s internal control over financial reporting.

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PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. Legal Proceedings of the Registrants’ 2006 Annual Report on Form 10-K and (b) Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.


Item 1A.	Risk Factors

At June 30, 2007, the Registrants’ risk factors changed compared to the risk factors described in Exelon’s 2006 Annual Report on Form 10-K as follows: (a) the two risk factors titled “ComEd may file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code if rate rollback and freeze legislation is enacted into law” and “Exelon and Generation will be negatively affected if ComEd files for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code” are no longer applicable as ComEd reached a Settlement with various representatives from the State of Illinois in July 2007 to address rate relief for Illinois electricity customers (see Note 5 of the Combined Notes to Consolidated Financial Statements for additional information) and (b) the Registrants identified the additional risk factors described below.

Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities.

Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s four retired units) addressing Generation’s ability to meet the NRC-estimated funding levels (NRC Funding Levels) including scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2006, Generation identified trust funds for 6 units, which were being funded at a rate less than anticipated with respect to NRC Funding Levels. In December 2006, Generation made a submission to the NRC addressing this issue, demonstrating in accordance with NRC requirements, that the trust funds for these 6 units indeed met NRC Funding Levels and remain adequately funded compared to the NRC Funding Level, when using alternate evaluation criteria allowed by NRC regulations. During the second quarter 2007, the NRC provided written notice that Generation has demonstrated reasonable assurance of decommissioning funding for these 6 units and, thus, was satisfied that Generation has met NRC Funding Levels for all of its nuclear fleet. The NRC Funding Levels are based upon the assumption that decommissioning will commence at the end of current licensed life.

Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to provide other means of funding its decommissioning obligations.

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Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds


	(c)	Exelon

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock in the quarter covered by this Report.


							Maximum Number
							(or Approximate
					Total Number of		Dollar Value) of
					Shares Purchased		Shares that May
	Total Number				As Part of Publicly		Yet Be Purchased
	of Shares		Average Price		Announced Plans		Under the Plans
Period	Purchased(a)		Paid per Share		or Programs(b)		or Programs

April 1 — April 30, 2007		19,893	$	67.63		—		(b	)
May 1 — May 31, 2007		5,399		72.51		—		(b	)
June 1 — June 30, 2007		11,176		76.01		—		(b	)

Total		36,468	$	70.92		—		(b	)


(a)		Shares other than those purchased as part of a publicly announced plan primarily represent restricted and performance shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares.

(b)		In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan. The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s Employee Stock Purchase Plan. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date.


Item 4.	Submission of Matters to a Vote of Security Holders

Exelon

Exelon held its 2007 Annual Meeting of Shareholders on May 8, 2007.

Proposal 1 was the election of five Class I directors to serve three-year terms expiring in 2010 and one Class III director to serve a two-year term expiring in 2009. The following directors were elected:


	Votes For		Votes Against		Votes Abstaining

Class I Directors
Nicholas DeBenedictis		458,731,310		83,641,677		7,044,481
Sue L. Gin		536,508,585		6,315,167		6,593,716
William C. Richardson		536,985,739		5,825,921		6,605,808
Thomas J. Ridge		421,335,195		119,271,938		8,810,335
Don Thompson		536,700,363		5,899,904		6,817,201

Class III Director
Stephen D. Steinour		536,762,711		5,781,618		6,873,139

Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2007. The shareholders approved the proposal with a vote of 540,749,869 votes cast for, 2,952,609 votes cast against, and 5,714,990 votes abstaining.

Proposal 3 was the amendment of Exelon’s Articles of Incorporation to allow for the annual election of all directors beginning in 2008. The shareholders approved the proposal with a vote of 533,610,590 votes cast for, 9,128,788 votes cast against, and 6,678,090 votes abstaining.

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Proposal 4 was a shareholder proposal to require shareholder approval of future severance benefits for executives. It received 166,061,956 votes cast for and 292,536,300 votes against. There were also 13,365,472 votes abstaining and 77,453,740 broker non-votes.


Item 5.	Other Information

PECO

During 2004, two elections were held at PECO, which resulted in union representation for PECO craft and call center employees in the Philadelphia service territory. The current affected workgroup totals approximately 1,200 employees. PECO and the International Brotherhood of Electrical Workers Local 614 began negotiations for initial agreements in 2005 and reached agreements in the second quarter of 2007. The agreements cover work hours, wages, benefits and working conditions for the represented employees. The agreements will not result in a material financial impact to PECO.

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Item 6.	Exhibits


Exhibit
No.		Description

	10-1	Amended and Restated Articles of Incorporation of Exelon Corporation
	10-2	Exelon Corporation Amended and Restated Bylaws
	10-3	Amendment Number One to the Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005)

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 filed by the following officers for the following companies:


31-1	—	Filed by John W. Rowe for Exelon Corporation
31-2	—	Filed by John F. Young for Exelon Corporation
31-3	—	Filed by John L. Skolds for Exelon Generation Company, LLC
31-4	—	Filed by John F. Young for Exelon Generation Company, LLC
31-5	—	Filed by Frank M. Clark for Commonwealth Edison Company
31-6	—	Filed by Robert K. McDonald for Commonwealth Edison Company
31-7	—	Filed by John L. Skolds for PECO Energy Company
31-8	—	Filed by John F. Young for PECO Energy Company

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 filed by the following officers for the following companies:


32-1	—	Filed by John W. Rowe for Exelon Corporation
32-2	—	Filed by John F. Young for Exelon Corporation
32-3	—	Filed by John L. Skolds for Exelon Generation Company, LLC
32-4	—	Filed by John F. Young for Exelon Generation Company, LLC
32-5	—	Filed by Frank M. Clark for Commonwealth Edison Company
32-6	—	Filed by Robert K. McDonald for Commonwealth Edison Company
32-7	—	Filed by John L. Skolds for PECO Energy Company
32-8	—	Filed by John F. Young for PECO Energy Company

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION





/s/ John W. Rowe John W. Rowe Chairman, Chief Executive Officer and President (Principal Executive Officer)		/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer (Principal Financial Officer)






/s/ Matthew F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller (Principal Accounting Officer)

July 25, 2007

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC





/s/ John W. Rowe John W. Rowe Chairman, Chief Executive Officer and President, Exelon		/s/ John L. Skolds John L. Skolds President (Principal Executive Officer)






/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)		/s/ Jon D. Veurink Jon D. Veurink Vice President and Controller (Principal Accounting Officer)

July 25, 2007

168

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY





/s/ Frank M. Clark Frank M. Clark Chairman and Chief Executive Officer (Principal Executive Officer)		/s/ J. Barry Mitchell J. Barry Mitchell President






/s/ Robert K. Mcdonald Robert K. McDonald Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer (Principal Financial Officer)		/s/ Matthew R. Galvanoni Matthew R. Galvanoni Principal Accounting Officer

July 25, 2007

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY





/s/ John L. Skolds John L. Skolds President, Exelon Energy Delivery (Principal Executive Officer)		/s/ Denis P. O’Brien Denis P. O’Brien President






/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)		/s/ Matthew R. Galvanoni Matthew R. Galvanoni Vice President and Controller (Principal Accounting Officer)

July 25, 2007

169

exv10w1

Exhibit 10.1

AMENDED AND RESTATED
ARTICLES OF INCORPORATION
OF
EXELON CORPORATION

ARTICLE I.

The name of the Corporation is Exelon Corporation (the “Corporation”).

ARTICLE II.

The address of the Corporation’s registered office in the Commonwealth of Pennsylvania is 2301 Market Street, the City of Philadelphia, County of Philadelphia, 19103.

ARTICLE III.
PURPOSES

The purpose or purposes for which the Corporation is incorporated are to engage in, and do any lawful act concerning, any or all lawful business for which corporations may be incorporated under the Business Corporation Law.

ARTICLE IV.
CAPITAL STOCK

The aggregate number of shares which the Corporation shall have authority to issue is 2,100,000 shares, divided into 2,000,000 shares of Common Stock, without par value (hereinafter called the “Common Stock”) and 100,000,000 shares of Preferred Stock, without par value (hereinafter called the “Preferred Stock”). The board of directors shall have the full authority permitted by law to determine the voting rights, if any, and designations, preferences, limitations, and special rights of any class or any series of any class of the Preferred Stock that may be desired to the extent not determined by the articles.

The following is a statement of the voting rights, designations, preferences, limitations, and the special rights granted to or imposed upon the Common Stock and the Preferred Stock:

PART 1
PREFERRED STOCK
DIVISION A
GENERAL PROVISIONS

Section 401. Vote Required to Increase Class or Series. Except as otherwise provided in the express terms of any series of the Preferred Stock, the number of authorized shares of the Preferred Stock or of any series thereof may be increased without a class or series vote or consent of the holders of the outstanding shares of the class or series affected.

DIVISION B
VARIATIONS AMONG SERIES OF PREFERRED STOCK
(Reserved)

PART 2
COMMON STOCK

Section 421. Voting Rights. At all meetings of the shareholders of the Corporation the holders of Common Stock shall be entitled to one vote for each share of Common Stock held by them respectively, except as otherwise expressly provided in this article.

Section 422. Dividend and Other Distribution Rights. Whenever full dividends or other distributions on all series of the Preferred Stock at the time outstanding having preferential dividend or other distribution rights shall have been paid or declared and set apart for payment or otherwise made, then such dividends (payable in cash or otherwise) or other distributions, as may be determined by the board of directors may be declared and paid or otherwise made on the Common Stock, but only out of funds legally available for the payment of such distributions.

Section 423. Liquidation Rights. In the event of any liquidation, dissolution or winding up of the Corporation, the assets and funds of the Corporation available for distribution to shareholders, after paying or providing for the payment to the holders of shares of all series of Preferred Stock of the full distributive amounts to which they are respectively entitled pursuant to the terms of such Preferred Stock, shall be divided among and paid to the holders of Common Stock according to their respective shares.

PART 3
GENERAL

Section 431. Preemptive Rights. Except as otherwise provided in the express terms of any class or series of shares, or in any contract, warrant or other instrument issued by the Corporation, no holder of shares of the Corporation shall be entitled, as such, as a matter of right to subscribe for or purchase any part of any issue of shares or other securities of the Corporation, of any class, series or kind whatsoever, and whether issued for cash, property, services, by way of dividends, or otherwise.

Section 432. Special Meeting of Shareholders. Except as otherwise provided by law or in the express terms of any class or series of shares, or in any contract, warrant, or other instrument issued by the Corporation, no holder of shares of the Corporation shall be entitled, as such, as a matter of right to call a special meeting of the shareholders.

Section 433. Amendments to Terms of Preferred Stock. If and to the extent provided by the express terms of any series of the Preferred Stock, the board of directors may, without the consent of the holders of the outstanding shares of such series or of the holders of any other shares of the Corporation (unless otherwise provided in the express terms of any such other shares), amend these articles of incorporation so as to change any of the terms of such series.

ARTICLE V.
MANAGEMENT

The following provisions shall govern the management of the business and affairs of the Corporation and the rights, powers or duties of its security holders, directors or officers:

Section 501. Effective Date of Article and Amendments Thereto. This article and any subsequent amendments thereto which require governmental approval, if any, shall take effect upon receipt of such governmental approval.

Section 502. Annual Election of Directors.

The board of directors of the Corporation shall not be classified in respect of the time for which they shall hold office. Except as otherwise provided in the express terms of any class or series of Preferred Stock with respect to the election of directors upon the occurrence of a default in the payment of dividends or in the performance of another express requirement of the terms of such Preferred Stock, from and after the 2008 annual meeting of the shareholders, the directors of the Corporation shall be elected at each annual meeting of the

shareholders for a one-year term expiring at the next annual meeting of the shareholders; provided that any director who was elected prior to the 2008 annual meeting of the shareholders for a term that extends until after the 2008 annual meeting of shareholders shall not be required to stand for election, and shall continue as a director, until the annual meeting at which the director’s term expires.

Section 503. Number of Directors.

The number of directors of the Corporation constituting the whole board shall be fixed solely by resolution adopted by a majority of the total number of directors that the Corporation would have if there were no vacancies on the board of directors, except as otherwise provided in the express terms of any class or series of Preferred Stock with respect to the election of directors upon the occurrence of a default in the payment of dividends or in the performance of another express requirement of the terms of such Preferred Stock.

Section 504. Straight Voting for Directors. The shareholders of the Corporation shall not have the right to cumulate their votes for the election of directors of the Corporation.

Section 505. Liability of Directors and Officers.

(a) A director shall not be personally liable, as such, for monetary damages (including, without limitation, any judgment, amount paid in settlement, penalty, punitive damages or expense of any nature, including, without limitation, attorney’s fees and disbursements) for any action taken, or any failure to take any action before, on or after the date of these Articles of Incorporation, unless:

(i) the director has breached or failed to perform the duties of his or her office under Subchapter B of Chapter 17 of the Business Corporation Law; and

(ii) the breach or failure to perform constitutes self-dealing, willful misconduct or recklessness.

(b) The provisions of paragraph (a) shall not apply to the responsibility or liability of a director pursuant to any criminal statute, or the liability of a director for the payment of taxes pursuant to local, State or Federal law.

(c) No amendment or repeal of this Section 505 shall have any effect on the liability or alleged liability of any director of the Corporation for or with respect to any such act on the part of such director occurring prior to the effective date of such amendment or repeal.

Section 506. Conduct of Officers. In lieu of the standards of conduct otherwise provided by law, officers of the Corporation shall be subject to the same standards of conduct, including standards of care and loyalty and rights of justifiable reliance, as shall at the time be applicable to directors of the Corporation.

Section 507. Bylaws. Except as otherwise provided in the express terms of any series of the shares of the Corporation, the bylaws and, except as otherwise stated in this Section 507, bylaws made by the board of directors or shareholders may be altered or repealed by the board of directors. The shareholders or the board of directors may adopt new bylaws except that the board of directors may not adopt, alter or repeal bylaws that the Business Corporation Law specifies may be adopted only by shareholders, and the board of directors may not alter or repeal any bylaw adopted by the shareholders that provides that it shall not be altered or repealed by the board of directors.

ARTICLE VI.
MISCELLANEOUS

Section 601. Headings. The headings of the various sections of these articles of incorporation are for convenience of reference only and shall not affect the interpretation of any of the provisions of these articles.

Section 602. Reserved Power of Amendment. These articles of incorporation may be amended in the manner and at the time prescribed by statute, and all rights conferred upon shareholders herein are granted subject
to this reservation.

As amended at the Annual Meeting of Shareholders on May 8, 2007

exv10w2

Exhibit 10.2

EXELON CORPORATION
AMENDED AND RESTATED
B Y L A W S

ARTICLE I.
Offices and Fiscal Year

Section 1.01 Registered Office. The registered office of the corporation in the Commonwealth of Pennsylvania shall be at 2301 Market Street, Philadelphia, Pennsylvania 19103.

Section 1.02 Other Offices. The corporation may also have offices at such other places within or without the Commonwealth of Pennsylvania as the board of directors may from time to time appoint or as may be necessary, advisable or appropriate for the business of the corporation.

Section 1.03 Fiscal Year. The fiscal year of the corporation shall begin on the first day of January in each year.

ARTICLE II.
Notice — Waivers — Meetings Generally

Section 2.01 Manner of Giving Notice.

(a) General Rule. Whenever written notice is required to be given to any person under the provisions of the Business Corporation Law or by the articles or these bylaws, it may be given to the person either personally or by sending a copy thereof by first class or express mail, postage prepaid, or by telegram (with messenger services specified), telex or TWX (with answerback received) or courier service, charges prepaid, or by facsimile transmission, to the address (or to the telex, TWX or facsimile transmission telephone number) of the person appearing on the books of the corporation, or as otherwise permitted by applicable law, or, in the case of directors, supplied by the director to the corporation for the purpose of notice. If the notice is sent by mail, telegraph or courier service, it shall be deemed to have been given to the person entitled thereto when deposited in the United States mail or with a telegraph office or courier service for delivery to that person or, in the case of telex or TWX, when dispatched or, in the case of facsimile transmission, when received. Notwithstanding the foregoing, written notice of any meeting of shareholders may be sent by any class of mail, postage prepaid, so long as such notice is sent at least 20 calendar days prior to the date of the meeting. A notice of meeting shall specify the place, day and hour of the meeting and any other information required by any other provision of the Business Corporation Law, the articles or these bylaws.

(b) Adjourned Shareholder Meetings. When a meeting of shareholders is adjourned, it shall not be necessary to give any notice of the adjourned meeting or of

the business to be transacted at an adjourned meeting, other than by announcement at the meeting at which the adjournment is taken, unless the board fixes a new record date for the adjourned meeting or the Business Corporation Law requires notice of the business to be transacted and such notice has not previously been given.

Section 2.02 Notice of Meetings of the Board of Directors.

Notice of a regular meeting of the board of directors need not be given. Notice of every special meeting of the board of directors shall be given to each director by telephone or in writing at least 24 hours (in the case of notice by telephone, telex, TWX, facsimile or other electronic transmission) or 48 hours (in the case of notice by telegraph, courier service or express mail) or five days (in the case of notice by first class mail) before the time at which the meeting is to be held. Every such notice shall state the time and place of the meeting. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the board need be specified in a notice of the meeting.

Section 2.03 Notice of Meetings of Shareholders.

(a) General Rule. Written notice of every meeting of the shareholders shall be given by, or at the direction of, the secretary or other authorized person to each shareholder of record entitled to vote at the meeting not less than five nor more than 90 calendar days prior to the date of the meeting. If the secretary neglects or refuses to give notice of a meeting, the person or persons calling the meeting may do so. In the case of a special meeting of shareholders, the notice shall specify the general nature of the business to be transacted.

(b) Notice of Action by Shareholders on Bylaws. In the case of a meeting of shareholders that has as one of its purposes adoption, amendment or repeal of these bylaws, written notice shall be given to each shareholder that the purpose, or one of the purposes, of the meeting is to consider the adoption, amendment or repeal of the bylaws. There shall be included in, or enclosed with, the notice a copy of the proposed amendment or a summary of the changes to be effected thereby.

Section 2.04 Waiver of Notice.

(a) Written Waiver. Whenever any written notice is required to be given under the provisions of the Business Corporation Law, the articles or these bylaws, a waiver thereof in writing, signed by the person or persons entitled to the notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of the notice. Neither the business to be transacted at, nor the purpose of, a meeting need be specified in the waiver of notice of the meeting.

(b) Waiver by Attendance. Attendance of a person at any meeting shall constitute a waiver of notice of the meeting except where a person attends a meeting

for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting was not lawfully called or convened.

Section 2.05 Modification of Proposal Contained in Notice. Whenever the language of a proposed resolution is included in a written notice of a meeting required to be given under the provisions of the Business Corporation Law or the articles or these bylaws, the meeting considering the resolution may without further notice adopt it with such clarifying or other amendments as do not enlarge its original purpose.

Section 2.06 Exception to Requirement of Notice.

(a) General Rule. Whenever any notice or communication is required to be given to any person under the provisions of the Business Corporation Law or by the articles or these bylaws or by the terms of any agreement or other instrument or as a condition precedent to taking any corporate action and communication with that person is then unlawful, the giving of the notice or communication to that person shall not be required.

(b) Shareholders Without Forwarding Addresses. Notice or other communications need not be sent to any shareholder with whom the corporation has been unable to communicate for more than 24 consecutive months because communications to the shareholder are returned unclaimed or the shareholder has otherwise failed to provide the corporation with a current address. Whenever the shareholder provides the corporation with a current address, the corporation shall recommence sending notices and other communications to the shareholder in the manner provided by these bylaws.

Section 2.07 Use of Conference Telephone and Similar Equipment. Any director may participate in any meeting of the board of directors or a committee thereof, and the board of directors may provide by resolution with respect to a specific meeting of shareholders or with respect to a class of meetings of shareholders that one or more persons may participate in a meeting of the shareholders of the corporation, by means of conference telephone, video conference or similar communications equipment by means of which all persons participating in the meeting can hear each other. Participation in a meeting pursuant to this Section shall constitute presence in person at the meeting.

ARTICLE III.
Shareholders

Section 3.01 Place of Meeting. Meetings of the shareholders of the corporation may be held at such place within or without the Commonwealth of Pennsylvania as may be designated by the Board of Directors, or in the absence of a designation by the Board of Directors, by the chairman of the board or the president and stated in the notice of a meeting.

Section 3.02 Annual Meeting. The annual meeting of the shareholders for the election of directors and the transaction of other business, if any, shall be held on such date and time as may be fixed by the board and stated in the notice of meetings (or, if the board fails to designate a date and time, at 10:30 a.m. on the fourth Wednesday in April of each year or, if such Wednesday is a legal holiday in the Commonwealth of Pennsylvania or in such other jurisdiction where such meeting may be held, the next succeeding business day). Failure to hold such meeting at the designated time or on the designated date or to elect some or all of the members of the board at such meeting or any adjournment thereof shall not affect otherwise valid corporate acts or work a forfeiture or dissolution of the corporation. If the annual meeting shall not have been called and held within six months after the designated time, any shareholder may call the meeting at any time thereafter.

Section 3.03 Special Meetings. Special meetings of the shareholders may be called at any time by resolution of the board of directors, which may fix the date, time and place of the meeting, and shall be called as provided in the terms of the Preferred Stock. If the board does not fix the date, time or place of the meeting, it shall be the duty of the secretary to do so. A date fixed by the secretary shall not be more than 60 calendar days after the date of the action calling the special meeting.

Section 3.04 Quorum and Adjournment.

(a) General Rule. A meeting of the shareholders of the corporation duly called shall not be organized for the transaction of business unless a quorum is present. Except as otherwise provided in the terms of the Preferred Stock, the presence of shareholders entitled to cast at least a majority of the votes that all shareholders are entitled to cast on a particular matter to be acted upon at the meeting shall constitute a quorum for the purposes of consideration and action on the matter. Shares of the corporation owned, directly or indirectly, by it shall not be counted in determining the total number of outstanding shares for quorum purposes at any given time.

(b) Withdrawal of a Quorum. The shareholders present at a duly organized meeting can continue to do business until adjournment notwithstanding the withdrawal of enough shareholders to leave less than a quorum.

(c) Adjournments Generally. Any regular or special meeting of the shareholders, including one at which directors are to be elected and one which cannot be organized because a quorum has not attended, may be adjourned, except as otherwise provided by the Business Corporation Law, for such period and to such place as the shareholders present and entitled to vote shall direct.

(d) Electing Directors at Adjourned Meeting. Those shareholders entitled to vote who attend a meeting called for the election of directors that has been previously adjourned for lack of a quorum, although less than a quorum as fixed in this Section of

these bylaws, shall nevertheless constitute a quorum for the purpose of electing directors.

(e) Other Action in Absence of Quorum. Those shareholders entitled to vote who attend a meeting of shareholders that has been previously adjourned for one or more periods aggregating at least 15 calendar days because of an absence of a quorum, although less than a quorum as fixed in this Section of these bylaws, shall nevertheless constitute a quorum for the purpose of acting upon any matter set forth in the notice of the meeting if the notice states that those shareholders who attend the adjourned meeting shall nevertheless constitute a quorum for the purpose of acting upon the matter.

Section 3.05 Action by Shareholders.

(a) General Rule. Except as otherwise provided in the Business Corporation Law or the articles or these bylaws, whenever any corporate action is to be taken by vote of the shareholders of the corporation, it shall be authorized upon receiving the affirmative vote of a majority of the votes cast by all shareholders entitled to vote thereon and, if any shareholders are entitled to vote thereon as a class, upon receiving the affirmative vote of a majority of the votes cast by the shareholders entitled to vote as a class, in each case at a duly organized meeting of shareholders. Except as otherwise provided in the terms of the Preferred Stock or when acting by unanimous consent to remove a director or directors, the shareholders of the corporation may act only at a duly organized meeting.

(b) Conduct of Business. Only such business will be conducted at an annual or special meeting of shareholders as shall have been properly brought before the meeting by or at the direction of the board of directors, or with respect to an annual meeting, by any shareholder who complies with the procedures set forth in this Section.

(1) For business to be properly brought before an annual meeting by a shareholder, the shareholder must have given to the secretary of the corporation timely written notice of the shareholder’s intention to make a proposal, in the manner and form prescribed herein.

(i) To be timely, a shareholder’s notice with respect to an annual meeting of shareholders must be addressed to the secretary of the corporation at the principal executive offices of the corporation and received by the secretary not less than 120 calendar days in advance of the first anniversary of the date on which the corporation first mailed its proxy materials to shareholders for the prior year’s annual meeting of shareholders, and this notice requirement shall not be affected by any adjournment of said meeting; provided, however, that in the event public announcement of the date of the annual meeting is not made at least 75 calendar days prior to the date of the annual meeting, notice by the shareholder to be timely must be so received not later than the close of

business on the 10th calendar day following the day on which public announcement is first made of the date of the annual meeting.

(ii) A shareholder’s notice to the secretary must set forth as to each matter the shareholder proposes to bring before the annual meeting (A) a description in reasonable detail of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (B) the name and address, as they appear on the corporation’s books, of the shareholder proposing such business and of the beneficial owner, if any, on whose behalf the proposal is made, (C) the class and number of shares of the corporation that are owned beneficially and of record by the shareholder proposing such business and by the beneficial owner, if any, on whose behalf the proposal is made, and (D) any material interest of such shareholder proposing such business and the beneficial owner, if any, on whose behalf the proposal is made in such business.

(iii) Notwithstanding the foregoing provisions of these bylaws, a shareholder must also comply with all applicable requirements of the Securities Exchange Act of 1934 (the “Exchange Act”) and the rules and regulations thereunder with respect to the matters set forth in this Section. For purposes of this Section, “public announcement” means disclosure in a press release reported by the Dow Jones News Service, Bloomberg Business News, or Reuters Economic Services or in a document publicly filed by the corporation with the Securities and Exchange Commission pursuant to Section 13, 14, or 15(d) of the Exchange Act, or publicly filed by the corporation with any national securities exchange or quotation service through which the corporation’s stock is listed or traded, or furnished by the corporation to its shareholders. Notwithstanding the foregoing, no notice of the date of the annual meeting is required for the advance notice provision of this Section 3.05 (b) to be effective if the annual meeting is held on such date as specified in Section 3.02 of these bylaws. Nothing in this Section will be deemed to affect any rights of shareholders to request inclusion of proposals in the corporation’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

(2) At a special meeting of shareholders, only such business may be conducted or considered as is properly brought before the meeting. To be properly brought before a special meeting, business must be (i) specified in the notice of the meeting (or any supplement thereto) given in accordance with Section 2.03 of these bylaws or (ii) otherwise brought before the meeting by the presiding officer or by or at the direction of a majority of the total number of directors that the corporation would have if there were no vacancies on the board of directors (the “Whole Board”).

(3) The determination of whether any business sought to be brought before any annual or special meeting of the shareholders is properly brought before such meeting in accordance with this Section of these bylaws will be made by the presiding officer of such meeting. If the presiding officer determines that any business is not properly brought before such meeting, he or she will so declare to the meeting and any such business will not be conducted or considered.

Section 3.06 Organization.

(a) Presiding Officer and Secretary of Meeting. At every meeting of the shareholders, the chairman of the board, or such other officer of the corporation designated by a majority of the Whole Board, will call meetings of shareholders to order or, in the case of vacancy in office and absence by action of the Whole Board, one of the following officers present in the order stated: The chief executive officer, if there be one, the president, if there be one, the vice presidents in their order of rank and seniority shall act as “presiding officer” of the meeting. The term “presiding officer” means an officer who presides over a meeting of shareholders. The secretary or, in the absence of the secretary, an assistant secretary, or, in the absence of both the secretary and assistant secretaries, a person appointed by the presiding officer of the meeting, shall act as secretary of the meeting.

(b) Rules of Conduct. Unless otherwise determined by the board of directors prior to the meeting, the presiding officer of the meeting of shareholders will determine the order of business and have the authority to make such rules or regulations for the conduct of meetings of shareholders as such presiding officer deems necessary, appropriate or convenient for the proper conduct of the meeting, including, without limitation, establishing an agenda or order of business for the meeting, rules and procedures for maintaining order at the meeting and the safety of those present, limitations on participation in such meeting to shareholders of record of the corporation and their duly authorized and constituted proxies, and such other persons as the board of directors or the presiding officer shall permit, restrictions on entry to the meeting after the time fixed for the commencement thereof, limitations on the time allotted to questions or comment by participants and regulation of the opening and closing of the polls for balloting on matters which are to be voted on by ballot. Unless, and to the extent determined by the board of directors or the presiding officer of the meeting, meetings of shareholders need not be conducted in accordance with rules of parliamentary procedure.

Section 3.07 Voting Rights of Shareholders. Unless otherwise provided in the articles, every shareholder of the corporation shall be entitled to one vote for every share standing in the name of the shareholder on the books of the corporation.

Section 3.08 Voting and other Action by Proxy.

(a) General Rule.

(1) Every shareholder entitled to vote at a meeting of shareholders may authorize another person to act for the shareholder by proxy.

(2) The presence of, or vote or other action at a meeting of shareholders by a proxy of a shareholder shall constitute the presence of, or vote or action by, the shareholder.

(3) Where two or more proxies of a shareholder are present, the corporation shall, unless otherwise expressly provided in the proxy, accept as the vote of all shares represented thereby the vote cast by a majority of them and, if a majority of the proxies cannot agree whether the shares represented shall be voted, or upon the manner of voting the shares, the voting of the shares shall be divided equally among those persons.

(b) Form of Proxy. Every proxy shall be in a form approved by the secretary of the corporation or as otherwise provided by the Business Corporation Law.

(c) Revocation. A proxy, unless coupled with an interest, shall be revocable at will, notwithstanding any other agreement or any provision in the proxy to the contrary, but the revocation of a proxy shall not be effective until written notice thereof has been given to the secretary of the corporation. An unrevoked proxy shall not be valid after three years from the date of its execution unless a longer time is expressly provided therein. A proxy shall not be revoked by the death or incapacity of the maker unless, before the vote is counted or the authority is exercised, written notice of the death or incapacity is given to the secretary of the corporation.

(d) Expenses. The corporation shall pay the reasonable expenses of solicitation of votes or proxies of shareholders by or on behalf of the board of directors or its nominees for election to the board, including solicitation by professional proxy solicitors and otherwise.

Section 3.09 Voting by Fiduciaries and Pledgees. Shares of the corporation standing in the name of a trustee or other fiduciary and shares held by an assignee for the benefit of creditors or by a receiver may be voted by the trustee, fiduciary, assignee or receiver. A shareholder whose shares are pledged shall be entitled to vote the shares until the shares have been transferred into the name of the pledgee, or a nominee of the pledgee, but nothing in this Section shall affect the validity of a proxy given to a pledgee or nominee.

Section 3.10 Voting by Joint Holders of Shares.

(a) General Rule. Where shares of the corporation are held jointly or as tenants in common by two or more persons, as fiduciaries or otherwise:

(1) if only one or more of such persons is present in person or by proxy, all of the shares standing in the names of such persons shall be deemed to be represented for the purpose of determining a quorum and the corporation shall accept as the vote of all the shares the vote cast by a joint owner or a majority of them; and

(2) if the persons are equally divided upon whether the shares held by them shall be voted or upon the manner of voting the shares, the voting of the shares shall be divided equally among the persons without prejudice to the rights of the joint owners or the beneficial owners thereof among themselves.

(b) Exception. If there has been filed with the secretary of the corporation a copy, certified by an attorney-at-law to be correct, of the relevant portions of the agreement under which the shares are held or the instrument by which the trust or estate was created or the order of court appointing them or of an order of court directing the voting of the shares, the persons specified as having such voting power in the latest document so filed, and only those persons, shall be entitled to vote the shares but only in accordance therewith.

Section 3.11 Voting by Corporations.

(a) Voting by Corporate Shareholders. Any domestic or foreign corporation for profit or not-for-profit that is a shareholder of this corporation may vote at meetings of shareholders of this corporation by any of its officers or agents, or by proxy appointed by any officer or agent, unless some other person, by resolution of the board of directors of the other corporation or a provision of its articles or bylaws, a copy of which resolution or provision certified to be correct by one of its officers has been filed with the secretary of this corporation, is appointed its general or special proxy in which case that person shall be entitled to vote the shares.

(b) Controlled Shares. Shares of this corporation owned, directly or indirectly, by it and controlled, directly or indirectly, by the board of directors of this corporation, as such, shall not be voted at any meeting and shall not be counted in determining the total number of outstanding shares for voting purposes at any given time.

Section 3.12 Determination of Shareholders of Record.

(a) Fixing Record Date. The board of directors may fix a time prior to the date of any meeting of shareholders as a record date for the determination of the shareholders entitled to notice of, or to vote at, the meeting, which time, except as otherwise provided in the articles or in the case of an adjourned meeting, shall be not more than 90 calendar days prior to the date of the meeting of shareholders. Only shareholders of record on the date fixed shall be so entitled notwithstanding any transfer of shares on the books of the corporation after any record date fixed as provided in this Subsection. The board of directors may similarly fix a record date for the determination of shareholders of record for any other purpose, except that the record date

fixed to determine the holders of Preferred Stock entitled to receive dividends thereon shall not precede the respective dividend payment date by more than 40 calendar days. When a determination of shareholders of record has been made as provided in this Section for purposes of a meeting, the determination shall apply to any adjournment thereof unless the board fixes a new record date for the adjourned meeting.

(b) Determination When Record Date Is Not Fixed. If a record date is not fixed:

(1) The record date for determining shareholders entitled to notice of or to vote at a meeting of shareholders shall be at the close of business on the day next preceding the day on which notice is given.

(2) The record date for determining shareholders for any other purpose shall be at the close of business on the day on which the board of directors adopts the resolution relating thereto.

(c) Certification by Nominee. The board of directors may adopt a procedure whereby a shareholder of the corporation may certify in writing to the corporation that all or a portion of the shares registered in the name of the shareholder are held for the account of a specified person or persons. Upon receipt by the corporation of a certification complying with the procedure, the persons specified in the certification shall be deemed, for the purposes set forth in the certification, to be the holders of record of the number of shares specified in place of the shareholder making the certification.

Section 3.13 Voting Lists.

(a) General Rule. The officer or agent having charge of the transfer books for shares of the corporation shall make a complete list of the shareholders entitled to vote at any meeting of shareholders, arranged in alphabetical order, with the address of and the number of shares held by each. The list shall be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder during the whole time of the meeting for the purposes thereof except that, if the corporation has 5,000 or more shareholders, in lieu of the making of the list the corporation may make the information therein available at the meeting by any other means.

(b) Effect of List. Failure to comply with the requirements of this Section shall not affect the validity of any action taken at a meeting prior to a demand at the meeting by any shareholder entitled to vote thereat to examine the list. The original share register or transfer book, or a duplicate thereof kept in the Commonwealth of Pennsylvania, shall be prima facie evidence as to who are the shareholders entitled to examine the list or share register or transfer book or to vote at any meeting of shareholders.

Section 3.14 Judges of Election.

(a) Appointment. In advance of any meeting of shareholders of the corporation, the board of directors may appoint judges of election, who need not be shareholders,

to act at the meeting or any adjournment thereof. If judges of election are not so appointed, the presiding officer of the meeting may appoint judges of election at the meeting. The number of judges shall be one or three. A person who is a candidate for an office to be filled at the meeting shall not act as a judge.

(b) Vacancies. In case any person appointed as a judge fails to appear or fails or refuses to act, the vacancy may be filled by appointment made by the board of directors in advance of the convening of the meeting or at the meeting by the presiding officer thereof.

(c) Duties. The judges of election shall determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, and the authenticity, validity and effect of proxies, receive votes or ballots, hear and determine all challenges and questions in any way arising in connection with the right to vote, count and tabulate all votes, determine the result and do such acts as may be proper to conduct the election or vote. The judges of election shall perform their duties impartially, in good faith, to the best of their ability and as expeditiously as is practical. If there are three judges of election, the decision, act or certificate of a majority shall be effective in all respects as the decision, act or certificate of all.

(d) Report. On request of the presiding officer of the meeting or of any shareholder, the judges shall make a report in writing of any challenge or question or matter determined by them, and execute a certificate of any fact found by them. Any report or certificate made by them shall be prima facie evidence of the facts stated therein.

Section 3.15 Minors as Security Holders. The corporation may treat a minor who holds shares or obligations of the corporation as having capacity to receive and to empower others to receive dividends, interest, principal and other payments or distributions, to vote or express consent or dissent and to make elections and exercise rights relating to such shares or obligations unless, in the case of payments or distributions on shares, the corporate officer responsible for maintaining the list of shareholders or the transfer agent of the corporation or, in the case of payments or distributions on obligations, the treasurer or paying officer or agent has received written notice that the holder is a minor.

ARTICLE IV.
Board of Directors

Section 4.01 Powers.

(a) General Rule. Unless otherwise provided by statute, all powers vested by law in the corporation shall be exercised by or under the authority of, and the business and affairs of the corporation shall be managed under the direction of, the board of directors.

(b) Personal Liability of Directors.

(1) A director shall not be personally liable, as such, for monetary damages (including, without limitation, any judgment, amount paid in settlement, penalty, punitive damages or expenses of any nature, including, without limitation, attorneys’ fees and disbursements) for any action taken, or any failure to take any action before, on or after the date of these bylaws, unless:

(i) the director has breached or failed to perform the duties of his or her office under Subchapter B of Chapter 17 of the Business Corporation Law; and

(ii) the breach or failure to perform constitutes self-dealing, willful misconduct or recklessness.

(2) The provisions of paragraph (1) shall not apply to the responsibility or liability of a director pursuant to any criminal statute, or the liability of a director for the payment of taxes pursuant to local, State or Federal law.

(3) No amendment or repeal of this Section 4.01 shall have any effect on the liability or alleged liability of any director of the corporation for or with respect to any such act on the part of such director occurring prior to the effective date of such amendment or repeal.

(c) Directors. A director shall stand in a fiduciary relation to the corporation and shall perform his duties as a director, including his duties as a member of any committee of the board upon which he may serve, in good faith, in a manner he reasonably believes to be in the best interests of the corporation and with such care, including reasonable inquiry, skill and diligence, as a person of ordinary prudence would use under similar circumstances. In performing his duties, a director shall be entitled to rely in good faith on information, opinions, reports or statements, including financial statements and other financial data, in each case prepared or presented by any of the following:

(1) One or more officers or employees of the corporation whom the director reasonably believes to be reliable and competent in the matters presented.

(2) Counsel, public accountants or other persons as to matters which the director reasonably believes to be within the professional or expert competence of such person.

(3) A committee of the board upon which he does not serve, duly designated in accordance with law, as to matters within its designated authority, which committee the director reasonably believes to merit confidence.

Section 4.02 Qualifications and Selection of Directors.

(a) Qualifications. Each director of the corporation shall be a natural person of full age who need not be a resident of the Commonwealth of Pennsylvania or a shareholder of the corporation, except as may be required under corporate governance principles approved by the board of directors. For purposes of Section 4.05, a director’s failure to hold the number of shares as and when required under corporate governance principles approved by the board of directors shall constitute cause for such director’s removal.

(b) Notice of Certain Nominations Required. Nominations for election of directors may be made by any shareholder entitled to vote for the election of directors if timely written notice in proper form (the “Notice”) of the shareholder’s intent to nominate a director at the meeting is given by the shareholder and received by the secretary of the corporation. To be timely, a shareholder’s Notice must be delivered to or mailed and received at the principal executive offices of the corporation not less than 120 calendar days before the first anniversary of the date on which the corporation first mailed its proxy materials for the prior year’s annual meeting of shareholders; provided, however, that in the event that public announcement of the date of the annual meeting is not made at least 75 calendar days prior to the date of the annual meeting, Notice by the shareholder to be timely must be so received not later than the close of business on the 10th calendar day following the day on which public announcement is first made of the date of the annual meeting. The requirements of this Subsection shall not apply to a nomination for directors made to the shareholders by the board of directors or a committee thereof.

(c) Contents of Notice. To be in proper written form, the Notice shall be in writing and shall contain or be accompanied by:

(1) the name and residence address of the nominating shareholder and of the beneficial owner, if any, on whose behalf the nomination is made;

(2) a representation that the shareholder giving the Notice is a holder of record of voting stock of the corporation entitled to vote at such annual meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the Notice;

(3) the class and number of shares of voting stock of the corporation owned beneficially and of record by the shareholder giving the Notice and by the beneficial owner, if any, on whose behalf the nomination is made;

(4) such information regarding each nominee as would have been required to be included in a proxy statement filed pursuant to Regulation 14A of the rules and regulations established by the Securities and Exchange Commission under the Exchange Act (or pursuant to any successor act or regulation) had proxies been solicited with respect to such nominee by the management or board of directors of the corporation;

(5) a description of all arrangements or understandings between or among any of (A) the shareholder giving the Notice, (B) the beneficial owner on whose behalf the Notice is given, (C) each nominee, and (D) any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the shareholder giving the Notice;

	(6)		a description of all arrangements or understandings among the shareholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the shareholder;

	(7)		a representation that each nominee meets the objective criteria for “independence” under applicable New York Stock Exchange listing standards and any additional objective criteria for “independence” under corporate governance principles approved by the board of directors; and

	(8)		the signed consent of each nominee to serve as a director of the corporation if so elected and to be bound by Sections 4.02 and 4.03 of the bylaws.

(d) Determination of Compliance. The presiding officer of the meeting may, if the facts warrant, determine and declare to the meeting that any nomination made at the meeting was not made in accordance with the procedures of this Section and, in such event, the presiding officer will so declare to the meeting, and the defective nomination shall be disregarded. Any such decision by the presiding officer shall be conclusive and binding upon all shareholders of the corporation for any purpose. Notwithstanding the foregoing provisions of this Section, a shareholder must also comply with all applicable requirements of the Exchange Act, and the rules and regulations thereunder, with respect to the matters set forth in this Section or otherwise relating to the nomination of directors by shareholders.

(e) Election of Directors. Except as otherwise provided in these bylaws, directors of the corporation shall be elected by the shareholders only at an annual meeting of shareholders, unless such election of directors is required by the terms of any series of Preferred Stock. In elections for directors, voting need not be by ballot, unless required by vote of the shareholders before the voting for election of directors begins. At a meeting for the election of directors, if the number of nominees exceeds the number of directorships to be filled, the directors shall be elected by a plurality of the votes cast. If in an election of directors in which the number of nominees does not exceed the number of directors to be elected, any nominee who is not an incumbent

director receives a plurality of the votes cast but does not receive a majority of the votes cast, the resignation of such nominee referred to in Section 4.03 will be automatically accepted. If the nominee is an incumbent director who is standing for re-election and such nominee receives a plurality of the votes cast but does not receive a majority of the votes cast, the committee of the board authorized to nominate candidates for election to the board will make a recommendation to the board on whether to accept the director’s resignation or whether other action should be taken. The director not receiving a majority of the votes cast will not participate in the committee’s recommendation or the board’s decision regarding the tendered resignation. The independent members of the board will consider the committee’s recommendation and publicly disclose the board’s decision and the basis for that decision within 90 days from the date of the certification of the final election results. If less than two members of the committee are elected at a meeting for the election of directors, the independent members of the board who were elected shall consider and act upon the tendered resignation. For purposes of this paragraph, a majority of the votes cast means that the number of shares voted “for” must exceed the number of shares voted “against” with respect to that director’s election.

Section 4.03 Number and Term of Office.

(a) Number. The board of directors shall consist of such number of directors as may be determined from time to time by resolution of a majority of the Whole Board.

(b) Term of Office. Each director shall hold office until the expiration of the term for which he or she was selected and until a successor has been selected and qualified or until his or her earlier death, resignation or removal. A decrease in the number of directors shall not have the effect of shortening the term of any incumbent director.

(c) Resignation — General. Any director may resign at any time upon written notice to the corporation. The resignation shall be effective upon receipt thereof by the corporation or at such subsequent time as shall be specified in the notice of resignation.

(d) Irrevocable Resignation. Each director who is nominated to stand for election shall, as a condition to such nomination, tender an irrevocable resignation in advance of the meeting for the election of directors. Such resignation will be effective if, pursuant to Section 4.02(e) of these bylaws, (a) the director does not receive a majority vote at the next meeting for the election of directors, and (b) in the case of a nominee who is an incumbent director, the board accepts the resignation.

(e) Annual Election of Board of Directors. The directors shall not be classified in respect to the time for which they shall hold office. Except as otherwise provided in the express terms of any class or series of Preferred Stock with respect to the election of directors upon the occurrence of a default in the payment of dividends or in the performance of another express requirement of the terms of such Preferred Stock, from and after the 2008 annual meeting of the shareholders, the directors of the

Corporation shall be elected at each annual meeting of the shareholders for a one-year term expiring at the next annual meeting of the shareholders; provided that any director who was elected prior to the 2008 annual meeting of the shareholders for a term that extends until after the 2008 annual meeting of shareholders shall not be required to stand for election, and shall continue as a director until the annual meeting at which the director’s term expires.

Section 4.04 Vacancies.

(a) General Rule. Except as otherwise provided in the terms of the Preferred Stock, vacancies in the board of directors, including vacancies resulting from an increase in the number of directors, may be filled by a majority vote of the remaining members of the board though less than a quorum, or by a sole remaining director, and each person so selected shall be a director to serve until the next annual meeting of shareholders, and until a successor has been selected and qualified or until his or her earlier death, resignation or removal.

(b) Action by Resigned Directors. When one or more directors resign from the board effective at a future date, the directors then in office, including those who have so resigned, shall have power by the applicable vote to fill the vacancies, the vote thereon to take effect when the resignations become effective.

Section 4.05 Removal of Directors.

(a) Removal by the Shareholders. The entire board of directors or any individual director may be removed from office by vote of the shareholders entitled to vote thereon only for cause. In case the board or any one or more directors are so removed, new directors may be elected at the same meeting. The repeal of a provision of the articles or bylaws prohibiting, or the addition of a provision to the articles or bylaws permitting, the removal by the shareholders of the board or a director without assigning any cause shall not apply to any incumbent director during the balance of the term for which the director was elected.

(b) Removal by the Board. The board of directors may declare vacant the office of a director who has been judicially declared of unsound mind or who has been convicted of an offense punishable by imprisonment for a term of more than one year or if, within 60 days after notice of his or her selection, the director does not accept the office either in writing or by attending a meeting of the board of directors.

Section 4.06 Place of Meetings. Meetings of the board of directors may be held at such place within or without the Commonwealth of Pennsylvania as the board of directors may from time to time appoint or as may be designated in the notice of the meeting.

Section 4.07 Organization of Meetings. At every meeting of the board of directors, the chairman of the board, if there be one, or, in the case of a vacancy in the

office or absence of the chairman of the board, the chairman of the corporate governance committee, or, in the case of a vacancy in the office or absence of both the chairman of the board and the chairman of the corporate governance committee, one of the following officers present in the order stated: the chief executive officer, the president, the vice presidents in their order of rank and seniority, or a person chosen by a majority of the directors present, shall act as chairman of the meeting. The

secretary or, in the absence of the secretary, an assistant secretary, or, in the absence of the secretary and the assistant secretaries, any person appointed by the chairman of the meeting, shall act as secretary of the meeting.

Section 4.08 Regular Meetings. Regular meetings of the board of directors shall be held at such time and place as shall be designated from time to time by resolution of the board of directors.

Section 4.09 Special Meetings. Special meetings of the board of directors shall be held whenever called by the chairman of the board, the chief executive officer, if there be one, or by two or more of the directors.

Section 4.10 Quorum of and Action by Directors.

(a) General Rule. A majority of the directors in office of the corporation shall be necessary to constitute a quorum for the transaction of business and except as otherwise provided in these bylaws the acts of a majority of the directors present and voting at a meeting at which a quorum is present shall be the acts of the board of directors.

(b) Action by Written Consent. Any action required or permitted to be taken at a meeting of the directors may be taken without a meeting if, prior or subsequent to the action, a consent or consents thereto by all of the directors in office is filed with the secretary of the corporation.

(c) Notation of Dissent. A director who is present at a meeting of the board of directors, or of a committee of the board, at which action on any corporate matter is taken shall be presumed to have assented to the action taken unless his or her dissent is entered in the minutes of the meeting or unless the director files a written dissent to the action with the secretary of the meeting before the adjournment thereof or transmits the dissent in writing to the secretary of the corporation immediately after the adjournment of the meeting. The right to dissent shall not apply to a director who voted in favor of the action. Nothing in this Section shall bar a director from asserting that minutes of the meeting incorrectly omitted his or her dissent if, promptly upon receipt of a copy of such minutes, the director notifies the secretary, in writing, of the asserted omission or inaccuracy.

Section 4.11 Committees of the Board.

(a) Establishment and Powers. The board of directors may, by resolution adopted by a majority of the directors in office, establish one or more committees to consist of one or more directors of the corporation. Any committee, to the extent provided in the resolution of the board of directors, shall have and may exercise all of the powers and authority of the board of directors except that a committee shall not have any power or authority as to the following:

(1) The submission to shareholders of any action requiring approval of shareholders under the Business Corporation Law.

(2) The creation or filling of vacancies in the board of directors.

(3) The adoption, amendment or repeal of these bylaws.

(4) The amendment or repeal of any resolution of the board that by its terms is amendable or repealable only by the board.

(5) Action on matters committed by a resolution of the board of directors to another committee of the board.

(b) Alternate Committee Members. The board may designate one or more directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of the committee or for the purposes of any written action by the committee. In the absence or disqualification of a member and alternate member or members of a committee, the member or members thereof present at any meeting and not disqualified from voting, whether or not constituting a quorum, may unanimously appoint another director to act at the meeting in the place of the absent or disqualified member.

(d) Committee Procedures. The term “board of directors” or “board,” when used in any provision of these bylaws relating to the organization or procedures of or the manner of taking action by the board of directors, shall be construed to include and refer to any executive or other committee of the board.

Section 4.12 Compensation. The board of directors shall have the authority to fix the compensation of directors for their services as directors and a director may be a salaried officer of the corporation.

ARTICLE V.
Officers

Section 5.01 Officers Generally.

(a) Number, Qualifications and Designation. The officers of the corporation shall be a chairman of the board, president, one or more vice presidents (which term shall include vice presidents, executive vice presidents and senior vice presidents), a secretary, a treasurer, and a chief executive officer , as the board of directors may designate by resolution, and such other officers as may be elected in accordance with the provisions of Section 5.03. Officers may but need not be directors or shareholders of the corporation. The president, secretary and treasurer shall be natural persons of full age. The board of directors may elect from among the members of the board a chairman of the board and vice chairman of the board who shall be officers of the corporation. Any number of offices may be held by the same person.

(b) Bonding. The corporation may secure the fidelity of any or all of its officers by bond or otherwise.

Section 5.02 Election, Term of Office and Resignations.

(a) Election and Term of Office. The officers of the corporation, except those elected by delegated authority pursuant to Section 5.03, shall be elected by the board of directors, and each such officer shall hold office at the discretion of the board until his or her death, resignation or removal with or without cause.

(b) Resignations. Any officer may resign at any time upon written notice to the corporation. The resignation shall be effective upon receipt thereof by the corporation or at such subsequent time as may be specified in the notice of resignation.

Section 5.03 Subordinate Officers, Committees and Agents. The board of directors may from time to time elect such other officers and appoint such committees, employees or other agents as the business of the corporation may require, including without limitation, one or more vice presidents, one or more assistant secretaries, and one or more assistant treasurers, each of whom shall hold office for such period, have such authority, and perform such duties as are provided in these bylaws, or as the board of directors may from time to time determine. The board of directors may delegate to any officer or committee the power to elect subordinate officers and to retain or appoint employees or other agents, or committees thereof, and to prescribe the authority and duties of such subordinate officers, committees, employees or other agents.

Section 5.04 Removal of Officers and Agents. Any officer or agent of the corporation may be removed by the board of directors with or without cause. The removal shall be without prejudice to the contract rights, if any, of any person so removed. Election or appointment of an officer or agent shall not of itself create contract rights.

Section 5.05 Vacancies. A vacancy in any office because of death, resignation, removal, disqualification, or any other cause, may be filled by the board of directors or by the officer or committee to which the power to fill such office has been delegated

pursuant to Section 5.03, as the case may be, and if the office is one for which these bylaws prescribe a term, shall be filled for the unexpired portion of the term.

Section 5.06 Authority.

(a) General Rule. All officers of the corporation, as between themselves and the corporation, shall have such authority and perform such duties in the management of the corporation as may be provided by or pursuant to resolutions or orders of the board of directors or, in the absence of controlling provisions in the resolutions or orders of the board of directors, as may be determined by or pursuant to these bylaws.

(b) Chief Executive Officer. The the board of directors may designate from time to time by resolution a chief executive officer. Such chief executive officer may be, but need not be, the president or chairman of the board.

Section 5.07 Chairman of the Board; Vice Chairman of the Board. Except as otherwise provided by these bylaws, the chairman of the board shall preside at all meetings of the shareholders and of the board of directors. The chairman of the board shall perform such other duties as may from time to time be requested by the board of directors. In addition, the board of directors may designate by resolution a vice chairman of the board with such duties as may from time to time be requested by the board of directors.

Section 5.08 The Chief Executive Officer. The chief executive officer, if there be one, may have general supervision over the business and operations of the corporation, subject however, to the control of the board of directors or the chairman of the board. Such chief executive officer may sign, execute, and acknowledge, in the name of the corporation, deeds, mortgages, bonds, contracts or other instruments, authorized by the board of directors, except in cases where the signing and execution thereof shall be expressly delegated by the board of directors, or by these bylaws, to some other officer or agent of the corporation; and, in general, may perform all duties incident to the office of chief executive officer and such other duties as from time to time may be assigned by the board of directors and the chairman of the board.

Section 5.09 The President. The president may have general supervision over the business and operations of the corporation, subject however, to the control of the board of directors, the chairman of the board and the chief executive officer, as applicable. The president may sign, execute, and acknowledge, in the name of the corporation, deeds, mortgages, bonds, contracts or other instruments, authorized by the board of directors, except in cases where the signing and execution thereof shall be expressly delegated by the board of directors, or by these bylaws, to some other officer or agent of the corporation; and, in general, may perform all duties incident to the office of president and such other duties as from time to time may be assigned by the board of directors, the chairman of the board and the chief executive officer, as applicable.

Section 5.10 The Vice Presidents. The vice presidents (which term shall include vice presidents, executive vice presidents and senior vice presidents) shall perform such duties as may from time to time be assigned to them by the board of directors or by the chief executive officer.

Section 5.11 The Secretary. The secretary or an assistant secretary shall attend all meetings of the shareholders and of the board of directors and shall record all the votes of the shareholders and of the directors and the minutes of the meetings of the shareholders and of the board of directors and of committees of the board in a book or books to be kept for that purpose; shall see that notices are given and records and reports properly kept and filed by the corporation as required by law; shall be the custodian of the seal of the corporation and see that it is affixed to all documents to be executed on behalf of the corporation under its seal; and, in general, shall perform all duties incident to the office of secretary, and such other duties as may from time to time be assigned by the board of directors or by the chief executive officer.

Section 5.12 The Treasurer. The treasurer or an assistant treasurer shall have or provide for the custody of the funds or other property of the corporation; shall collect and receive or provide for the collection and receipt of moneys earned by or in any manner due to or received by the corporation; shall deposit all funds in his, or its custody as treasurer in such banks or other places of deposit as the board of directors may from time to time designate; shall, whenever so required by the board of directors, render an account showing all transactions as treasurer, and the financial condition of the corporation; and, in general, shall discharge such other duties as may from time to time be assigned by the board of directors or by the chief executive officer.

Section 5.13 Salaries. The salaries of the officers elected by the board of directors shall be fixed from time to time by the board of directors or by such officer or committee as may be designated by resolution of the board. The salaries or other compensation of any other officers, employees and other agents shall be fixed from time to time by the officer or committee to which the power to elect such officers or to retain or appoint such employees or other agents has been delegated pursuant to Section 5.03. No officer shall be prevented from receiving such salary or other compensation by reason of the fact that the officer is also a director of the corporation.

ARTICLE VI.
Certificates of Stock, Transfer, Etc.

Section 6.01 Share Certificates.

(a) Form of Certificates. Certificates for shares of the corporation shall be in such form as approved by the board of directors, and shall state that the corporation is incorporated under the laws of the Commonwealth of Pennsylvania, the name of the person to whom issued, and the number and class of shares and the designation of the series (if any) that the certificate represents. Certificates for shares of the corporation shall set forth upon the face or back of the certificate (or shall state on the face or back of the certificate that the corporation will furnish to any shareholder upon request and without charge), a full or summary statement of the designations, voting rights, preferences, limitations and special rights of the shares of each class or series authorized to be issued so far as they have been fixed and determined and the authority of the board of directors to fix and determine the designations, voting rights, preferences, limitations and special rights of the classes and series of shares of the corporation.

(b) Share Register. The share register or transfer books and blank share certificates shall be kept by the treasurer or by any transfer agent or registrar designated by the board of directors for that purpose.

Section 6.02 Issuance. The share certificates of the corporation shall be numbered and registered in the share register or transfer books of the corporation as they are issued. They shall be executed in such manner as the board of directors shall determine.

Section 6.03 Transfer. Transfers of shares shall be made on the share register or transfer books of the corporation upon surrender of the certificate therefor, endorsed by the person named in the certificate or by an attorney lawfully constituted in writing. No transfer shall be made inconsistent with the provisions of the Uniform Commercial Code, 13 Pa.C.S. §§ 8101 et seq., and its amendments and supplements.

Section 6.04 Record Holder of Shares. The corporation shall be entitled to treat the person in whose name any share or shares of the corporation stand on the books of the corporation as the absolute owner thereof, and shall not be bound to recognize any equitable or other claim to, or interest in, such share or shares on the part of any other person.

Section 6.05 Lost, Destroyed or Mutilated Certificates. The holder of any shares of the corporation shall immediately notify the corporation of any loss, destruction or mutilation of the certificate therefor, and the officers of the corporation may, in their discretion, cause a new certificate or certificates to be issued to such holder, in case of mutilation of the certificate, upon the surrender of the mutilated certificate or, in case of loss or destruction of the certificate, upon satisfactory proof of such loss or destruction

and, if such officers shall so determine, the deposit of a bond in such form and in such sum, and with such surety or sureties, as any of them may direct.

ARTICLE VII.
Indemnification of Directors, Officers and
Other Authorized Representatives

Section 7.01 Right to Indemnification. Each person who was or is made a party or is threatened to be made a party to or is otherwise involved in any claim, action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a “proceeding”), by reason of the fact that he or she is or was a director or an officer of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an “indemnitee”), whether the basis of such proceeding is alleged action in an official capacity as a director, officer, employee or agent or in any other capacity while serving as a director, officer, employee or agent, shall be indemnified and held harmless by the corporation to the fullest extent permitted or required by the Business Corporation Law, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the corporation to provide broader indemnification rights than such law permitted the corporation to provide prior to such amendment), against all expense, liability and loss (including attorneys’ fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such indemnitee in connection therewith; provided, however, that, except as provided in Section 7.03 of this Article VII with respect to proceedings to enforce rights to indemnification, the corporation shall indemnify any such indemnitee in connection with a proceeding (or part thereof) initiated by such indemnitee only if such proceeding (or part thereof) was authorized by the board of directors of the corporation.

Section 7.02 Right to Advancement of Expenses. The right to indemnification conferred in Section 7.01 of this Article VII shall include the right to be paid by the corporation the expenses (including, without limitation, attorneys’ fees and expenses) incurred in defending any such proceeding in advance of its final disposition (hereinafter an “advancement of expenses”); provided, however, that, if the Business Corporation Law so requires, an advancement of expenses incurred by an indemnitee in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such indemnitee, including, without limitation, service to an employee benefit plan) shall be made only upon delivery to the corporation of an undertaking (hereinafter an “undertaking”), by or on behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (hereinafter a “final adjudication”) that such indemnitee is not entitled to be indemnified for such expenses under this Section 7.02 or otherwise. The rights to indemnification and to the advancement of expenses conferred in Sections 7.01 and 7.02 of this Article VII shall be contract rights and such rights shall continue as to an indemnitee who has ceased to be a director, officer,

employee or agent and shall inure to the benefit of the indemnitee’s heirs, executors and administrators. Any repeal, amendment or modification hereof shall be prospective only and shall not affect any rights or obligations then existing. Each person who shall act as an indemnitee of the corporation shall be deemed to be doing so in reliance upon the rights provided by this Article.

Section 7.03 Right of Indemnitee to Bring Suit. If a claim under Section 7.01 or 7.02 of this Article VII is not paid in full by the corporation within 60 calendar days after a written claim has been received by the corporation, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be 20 calendar days, the indemnitee may at any time thereafter bring suit against the corporation to recover the unpaid amount of the claim. If successful in whole or in part in any such suit, or in a suit brought by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking, the indemnitee shall be entitled to be paid also the expense of prosecuting or defending such suit. In (i) any suit brought by the indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and (ii) any suit brought by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking, the corporation shall be entitled to recover such expenses upon a final adjudication that, the indemnitee has not met any applicable standard for indemnification set forth in the Business Corporation Law. Neither the failure of the corporation (including its board of directors, independent legal counsel or shareholders) to have made a determination prior to the commencement of such suit that indemnification of the indemnitee is proper in the circumstances because the indemnitee has met the applicable standard of conduct set forth in the Business Corporation Law, nor an actual determination by the corporation (including its board of directors, independent legal counsel or shareholders) that the indemnitee has not met such applicable standard of conduct, shall create a presumption that the indemnitee has not met the applicable standard of conduct or, in the case of such a suit brought by the indemnitee, be a defense to such suit. In any suit brought by the indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or brought by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the indemnitee is not entitled to be indemnified, or to such advancement of expenses, under this Article VII or otherwise shall be on the corporation.

Section 7.04 Non-Exclusivity of Rights. The rights to indemnification and to the advancement of expenses conferred in this Article VII shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, the articles, these bylaws, agreement, vote of shareholders or disinterested directors or otherwise.

Section 7.05 Insurance. The corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the corporation or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not the corporation would have the power to

indemnify such person against such expense, liability or loss under the Business Corporation Law.

Section 7.06 Indemnification of Employees and Agents of the Corporation. The corporation may, to the extent authorized from time to time by the board of directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of the corporation to the fullest extent of the provisions of this Article VII with respect to the indemnification and advancement of expenses of directors and officers of the corporation.

Section 7.07 Interpretation. The provisions of this Article are intended to constitute bylaws authorized by Section 1746 of the Business Corporation Law.

ARTICLE VIII.
Emergency Bylaws

Section 8.01 Scope of Article. This Article shall be applicable during any emergency resulting from a catastrophe as a result of which a quorum of the board of directors cannot readily be assembled. To the extent not in conflict with this Article, these bylaws shall remain in effect during the emergency.

Section 8.02 Special Meetings of the Board. A special meeting of the board of directors may be called by any director by means feasible at the time.

Section 8.03 Emergency Committee of the Board.

(a) Composition. The emergency committee of the board shall consist of nine persons standing highest on the following list who are available and able to act:

The chief executive officer.

Members of the board of directors.

President.

The individual who, immediately prior to the emergency, was the senior officer in charge of nuclear operations.

The individual who, immediately prior to the emergency, was the senior officer in charge of other operations.

The individual who, immediately prior to the emergency, was the senior officer in charge of finance operations.

Other officers.

Where more than one person holds any of the listed ranks, the order of precedence shall be determined by length of time in rank. Each member of the emergency committee thus constituted shall continue to act until replaced by an individual standing higher on the list. The emergency committee shall continue to act until a quorum of the

board of directors is available and able to act. If the corporation has no directors, the emergency committee shall cause a special meeting of shareholders for the election of directors to be called and held as soon as practicable.

(b) Powers. The emergency committee shall have and may exercise all of the powers and authority of the board of directors, including the power to fill a vacancy in any office of the corporation or to designate a temporary replacement for any officer of the corporation who is unavailable, but shall not have the power to fill vacancies in the board of directors.

(d) Status. Each member of the emergency committee who is not a director shall during his or her service as such be entitled to the rights and immunities conferred by law, the articles and these bylaws upon directors of the corporation and upon persons acting in good faith as a representative of the corporation during an emergency.

ARTICLE IX.
Miscellaneous

Section 9.01 Corporate Seal. The corporation may have a corporate seal in the form of a circle containing the name of the corporation, the year of incorporation and such other details as may be approved by the board of directors from time to time.

Section 9.02 Checks. All checks, notes, bills of exchange or other orders in writing shall be signed by such person or persons as the board of directors or any person authorized by resolution of the board of directors may from time to time designate.

Section 9.03 Contracts. Except as otherwise provided in the Business Corporation Law in the case of transactions that require action by the shareholders, the board of directors may authorize any officer or agent to enter into any contract or to execute or deliver any instrument on behalf of the corporation, and such authority may be general or confined to specific instances.

Section 9.04 Interested Directors or Officers; Quorum.

(a) General Rule. A contract or transaction between the corporation and one or more of its directors or officers or between the corporation and another domestic or foreign corporation for profit or not-for-profit, partnership, joint venture, trust or other enterprise in which one or more of its directors or officers are directors or officers or have a financial or other interest, shall not be void or voidable solely for that reason, or solely because the director or officer is present at or participates in the meeting of the

board of directors that authorizes the contract or transaction, or solely because his, her or their votes are counted for that purpose, if:

(1) the material facts as to the relationship or interest and as to the contract or transaction are disclosed or are known to the board of directors and the board authorizes the contract or transaction by the affirmative votes of a majority of the disinterested directors even though the disinterested directors are less than a quorum;

(2) the material facts as to his or her relationship or interest and as to the contract or transaction are disclosed or are known to the shareholders entitled to vote thereon and the contract or transaction is specifically approved in good faith by vote of those shareholders; or

(3) the contract or transaction is fair as to the corporation as of the time it is authorized, approved or ratified by the board of directors or the shareholders.

(b) Quorum. Common or interested directors may be counted in determining the presence of a quorum at a meeting of the board which authorizes a contract or transaction specified in Subsection (a).

Section 9.05 Deposits. All funds of the corporation shall be deposited from time to time to the credit of the corporation in such banks, trust companies or other depositories as the board of directors may approve or designate, and all such funds shall be withdrawn only upon checks signed by such one or more officers or employees as the board of directors shall from time to time determine.

Section 9.06 Corporate Records.

(a) Required Records. The corporation shall keep complete and accurate books and records of account, minutes of the proceedings of the incorporators, shareholders and directors and a share register giving the names and addresses of all shareholders and the number and class of shares held by each. The share register shall be kept at either the registered office of the corporation in the Commonwealth of Pennsylvania or at its principal place of business wherever situated or at the office of its registrar or transfer agent. Any books, minutes or other records may be in written form or any other form capable of being converted into written form within a reasonable time.

(b) Right of Inspection. Every shareholder shall, upon written verified demand stating the purpose thereof, have a right to examine, in person or by agent or attorney, during the usual hours for business for any proper purpose, the share register, books and records of account, and records of the proceedings of the incorporators, shareholders and directors and to make copies or extracts therefrom. A proper purpose shall mean a purpose reasonably related to the interest of the person as a shareholder. In every instance where an attorney or other agent is the person who

seeks the right of inspection, the demand shall be accompanied by a verified power of attorney or other writing that authorizes the attorney or other agent to so act on behalf of the shareholder. The demand shall be directed to the corporation at its registered office in the Commonwealth of Pennsylvania or at its principal place of business wherever situated.

Section 9.07 Amendment of Bylaws.

(a) General Rule. Except as otherwise provided in the express terms of any series of the shares of the corporation, any one or more of the foregoing bylaws and, except as otherwise stated in this Section 9.07(a), any other bylaws made by the board of directors or shareholders may be altered or repealed by the board of directors. The shareholders or the board of directors may adopt new bylaws except that the board of directors may not adopt, alter or repeal bylaws that the Business Corporation Law specifies may be adopted only by shareholders, and the board of directors may not alter or repeal any bylaw adopted by the shareholders that presumes that such bylaw shall not be altered or repealed by the board of directors.

(b) Effective Date. Any change in these bylaws shall take effect when adopted unless otherwise provided in the resolution effecting the change.

As adopted December 5, 2006.

exv10w3

AMENDMENT NUMBER ONE
TO THE
EXELON CORPORATION
STOCK DEFERRAL PLAN
(As Amended and Restated Effective January 1, 2005)

The Exelon Corporations Stock Deferral Plan, as amended and restated effective January 1, 2005 (the “Plan”), is hereby amended in the following respect:

Section 5.3(b) of the Plan is amended in its entirety to read as follows:

(b) Each Participant may elect to receive a distribution of such Participant’s Deferred Stock Account attributable to Plan Years prior to January 1, 2007 in a lump sum payment of Exelon Stock in the third quarter of 2007, by submitting such election on or before December 31, 2006 in accordance with procedures prescribed by the Plan Administrator, provided that such election shall be null and void if such Participant’s distribution under the Plan otherwise would be made or commence prior to January 1, 2007. A Participant who files such a lump sum election, whose position is Executive Vice President or above and who has achieved two times his or her stock ownership requirement may elect to receive such distribution in the form of Exelon Stock, in cash, or one quarter in Exelon Stock and three quarters in cash.

Executed this ____ day of ___________, 2007.

EXELON CORPORATION


By:

		S. Gary Snodgrass
		Executive Vice President and
		Chief Human Resources Officer

exv31w1

Exhibit 31-1

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John W. Rowe, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Designed such internal control over financial reporting, or caused such internal control over financing reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John W. Rowe

Chairman, Chief Executive Officer and President

(Principal Executive Officer)

Date: July 25, 2007

170

exv31w2

Exhibit 31-2

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John F. Young, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Designed such internal control over financial reporting, or caused such internal control over financing reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John F. Young

Executive Vice President, Finance and Markets and

Chief Financial Officer

(Principal Financial Officer)

Date: July 25, 2007

171

exv31w3

Exhibit 31-3

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John L. Skolds, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John L. Skolds

President

(Principal Executive Officer)

Date: July 25, 2007

172

exv31w4

Exhibit 31-4

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John F. Young, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John F. Young

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Date: July 25, 2007

173

exv31w5

Exhibit 31-5

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	Frank M. Clark, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Frank M. Clark

Chairman and Chief Executive Officer

(Principal Executive Officer)

Date: July 25, 2007

174

exv31w6

Exhibit 31-6

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	Robert K. McDonald, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Robert K. McDonald

Senior Vice President, Chief Financial Officer,

Treasurer and Chief Risk Officer

(Principal Financial Officer)

Date: July 25, 2007

175

exv31w7

Exhibit 31-7

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John L. Skolds, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John L. Skolds

President, Exelon Energy Delivery

(Principal Executive Officer)

Date: July 25, 2007

176

exv31w8

Exhibit 31-8

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934


I,	John F. Young, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:


	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


	(b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


	(c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John F. Young

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Date: July 25, 2007

177

exv32w1

Exhibit 32-1

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Exelon Corporation for the quarterly period ended June 30, 2007, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

/s/ John W. Rowe

John W. Rowe

Chairman, Chief Executive Officer and President

Date: July 25, 2007

178

exv32w2

Exhibit 32-2

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ John F. Young

John F. Young

Executive Vice President, Finance and

Markets and Chief Financial Officer

Date: July 25, 2007

179

exv32w3

Exhibit 32-3

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended June 30, 2007, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

/s/ John L. Skolds

John L. Skolds

President

Date: July 25, 2007

180

exv32w4

Exhibit 32-4

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ John F. Young

John F. Young

Executive Vice President and Chief Financial Officer

Date: July 25, 2007

181

exv32w5

Exhibit 32-5

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Commonwealth Edison Company for the quarterly period ended June 30, 2007, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

/s/ Frank M. Clark

Frank M. Clark

Chairman and Chief Executive Officer

Date: July 25, 2007

182

exv32w6

Exhibit 32-6

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ Robert K. McDonald

Robert K. McDonald

Senior Vice President, Chief Financial

Officer, Treasurer and Chief Risk Officer

Date: July 25, 2007

183

exv32w7

Exhibit 32-7

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of PECO Energy Company for the quarterly period ended June 30, 2007, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

/s/ John L. Skolds

John L. Skolds

President

Exelon Energy Delivery

Date: July 25, 2007

184

exv32w8

Exhibit 32-8

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ John F. Young

John F. Young

Executive Vice President and Chief Financial Officer

Date: July 25, 2007

185