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 September 30, 2006
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 — 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
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
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-6900	23-3064219

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 September 30, 2006 was:


Exelon Corporation Common Stock, without par value		670,954,514
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,519
PECO Energy Company Common Stock, without par value		170,478,507
Exelon Generation Company, LLC		not applicable

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

Commonwealth Edison Company

PECO Energy Company

Exelon Generation Company, LLC

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

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (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’ 2005 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: Exelon — Note 20, ComEd — Note 17, PECO — Note 15 and Generation — Note 17, 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.

EXELON CORPORATION

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions, except per share data)	2006			2005			2006			2005

Operating revenues	$	4,401		$	4,473		$	11,960		$	11,519
Operating expenses
Purchased power		996			1,210			2,092			2,442
Fuel		489			482			1,928			1,598
Operating and maintenance		1,084			900			2,989			2,776
Depreciation and amortization		400			358			1,135			1,003
Impairment of goodwill		776			—			776			—
Taxes other than income		218			211			582			560

Total operating expenses		3,963			3,161			9,502			8,379

Operating income		438			1,312			2,458			3,140

Other income and deductions
Interest expense		(154	)		(139	)		(460	)		(374	)
Interest expense to affiliates, net		(64	)		(77	)		(203	)		(241	)
Equity in losses of unconsolidated affiliates		(13	)		(39	)		(74	)		(107	)
Other, net		114			11			205			108

Total other income and deductions		(117	)		(244	)		(532	)		(614	)

Income from continuing operations before income taxes		321			1,068			1,926			2,526
Income taxes		366			344			929			779

Income (loss) from continuing operations		(45	)		724			997			1,747

Discontinued operations
Loss from discontinued operations (net of taxes of $0 and $(2) for the three and nine months ended September 30, 2005, respectively)		—			—			—			(3	)
Gain on disposal of discontinued operations (net of taxes of $0, $1, $3 and $5 for the three and nine months ended September 30, 2006 and 2005, respectively)		1			1			3			16

Income from discontinued operations, net		1			1			3			13

Net income (loss)		(44	)		725			1,000			1,760

Other comprehensive income (loss), net of income taxes
Minimum pension liability		—			—			—			2
Change in unrealized gain (loss) on cash-flow hedges		153			(161	)		385			(294	)
Unrealized gain (loss) on marketable securities		33			15			48			(9	)

Other comprehensive income (loss)		186			(146	)		433			(301	)

Comprehensive income	$	142		$	579		$	1,433		$	1,459

Average shares of common stock outstanding:
Basic		671			670			670			669
Diluted		671			677			676			676

Earnings per average common share — basic:
Income (loss) from continuing operations	$	(0.07	)	$	1.08		$	1.49		$	2.61
Income from discontinued operations		—			—			—			0.02

Net income (loss)	$	(0.07	)	$	1.08		$	1.49		$	2.63

Earnings per average common share — diluted:
Income (loss) from continuing operations	$	(0.07	)	$	1.07		$	1.48		$	2.58
Income from discontinued operations		—			—			—			0.02

Net income (loss)	$	(0.07	)	$	1.07		$	1.48		$	2.60

Dividends per common share	$	0.40		$	0.40		$	1.20		$	1.20

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	1,000		$	1,760
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		1,621			1,477
Deferred income taxes and amortization of investment tax credits		(20	)		487
Impairment charges		893			—
Other non-cash operating activities		255			264
Changes in assets and liabilities:
Accounts receivable		172			(213	)
Inventories		(23	)		(54	)
Accounts payable, accrued expenses and other current liabilities		(307	)		61
Counterparty collateral asset		236			(203	)
Counterparty collateral liability		159			104
Income taxes		64			257
Net realized and unrealized mark-to-market and hedging transactions		(115	)		(168	)
Pension and non-pension postretirement benefit contributions		(49	)		(2,059	)
Other assets and liabilities		(381	)		(167	)

Net cash flows provided by operating activities		3,505			1,546

Cash flows from investing activities
Capital expenditures		(1,752	)		(1,521	)
Proceeds from nuclear decommissioning trust fund sales		3,584			3,234
Investment in nuclear decommissioning trust funds		(3,808	)		(3,387	)
Acquisitions of businesses, net of cash acquired		—			(97	)
Proceeds from sales of investments, long-lived assets and wholly owned subsidiaries, net of $32 of cash sold during the nine months ended September 30, 2005		2			107
Change in restricted cash		12			38
Other investing activities		(24	)		(59	)

Net cash flows used in investing activities		(1,986	)		(1,685	)

Cash flows from financing activities
Issuance of long-term debt		920			1,788
Retirement of long-term debt		(64	)		(382	)
Retirement of long-term debt to financing affiliates		(691	)		(639	)
Issuance of short-term debt		—			2,500
Retirement of short-term debt		—			(2,200	)
Change in other short-term debt		(837	)		(344	)
Dividends paid on common stock		(803	)		(804	)
Proceeds from employee stock plans		149			193
Purchase of treasury stock		(54	)		(262	)
Other financing activities		—			(57	)

Net cash flows used in financing activities		(1,380	)		(207	)

Increase (decrease) in cash and cash equivalents		139			(346	)
Cash and cash equivalents at beginning of period		140			499

Cash and cash equivalents at end of period	$	279		$	153

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,			December 31,
(In millions)	2006			2005

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Commercial paper and notes payable	$	453		$	1,290
Long-term debt due within one year		555			407
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year		714			507
Accounts payable		1,147			1,467
Mark-to-market derivative liabilities		746			1,282
Accrued expenses		1,008			1,005
Other		904			605

Total current liabilities		5,527			6,563

Long-term debt		8,474			7,759
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust		2,556			3,456
Long-term debt to other financing trusts		545			545
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,414			5,078
Asset retirement obligations		3,727			4,157
Pension obligations		296			268
Non-pension postretirement benefit obligations		1,115			1,014
Spent nuclear fuel obligation		938			906
Regulatory liabilities		2,282			2,170
Mark-to-market derivative liabilities		200			522
Other		785			798

Total deferred credits and other liabilities		14,757			14,913

Total liabilities		31,859			33,236

Commitments and contingencies
Minority interest of consolidated subsidiaries		—			1
Preferred securities of subsidiaries		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 671 and 666 shares outstanding at September 30, 2006 and December 31, 2005, respectively)		8,261			7,987
Treasury stock, at cost (10 and 9 shares held at September 30, 2006 and December 31, 2005, respectively)		(498	)		(444	)
Retained earnings		3,130			3,206
Accumulated other comprehensive loss, net		(1,191	)		(1,624	)

Total shareholders’ equity		9,702			9,125

Total liabilities and shareholders’ equity	$	41,648		$	42,449

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,837		$	1,945		$	4,712		$	4,814
Operating revenues from affiliates		3			3			8			8

Total operating revenues		1,840			1,948			4,720			4,822

Operating expenses
Purchased power		87			91			260			247
Purchased power from affiliate		907			991			2,363			2,514
Operating and maintenance		155			161			484			475
Operating and maintenance from affiliates		55			50			160			139
Impairment of goodwill		776			—			776			—
Depreciation and amortization		115			111			320			308
Taxes other than income		83			81			234			232

Total operating expenses		2,178			1,485			4,597			3,915

Operating income (loss)		(338	)		463			123			907

Other income and deductions
Interest expense		(60	)		(49	)		(174	)		(152	)
Interest expense to affiliates, net		(18	)		(22	)		(56	)		(68	)
Equity in losses of unconsolidated affiliates		(2	)		(3	)		(8	)		(11	)
Other, net		89			(10	)		90			—

Total other income and deductions		9			(84	)		(148	)		(231	)

Income (loss) before income taxes		(329	)		379			(25	)		676
Income taxes		177			155			300			273

Net income (loss)		(506	)		224			(325	)		403

Other comprehensive gain (loss), net of income taxes
Change in unrealized gain (loss) on cash-flow hedges		(2	)		21			(2	)		—
Unrealized gain on marketable securities		1			1			1			1

Other comprehensive income (loss)		(1	)		22			(1	)		1

Comprehensive income (loss)	$	(507	)	$	246		$	(326	)	$	404

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income (loss)	$	(325	)	$	403
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation, amortization and accretion		320			308
Deferred income taxes and amortization of investment tax credits		20			190
Impairment of goodwill		776			—
Other non-cash operating activities		97			104
Changes in assets and liabilities:
Accounts receivable		(34	)		(189	)
Inventories		(16	)		1
Accounts payable, accrued expenses and other current liabilities		7			17
Receivables from and payables to affiliates		(39	)		8
Income taxes		75			30
Net realized and unrealized mark-to-market and hedging transactions		5			—
Pension and non-pension postretirement benefit contributions		(2	)		(807	)
Other assets and liabilities		(143	)		(28	)

Net cash flows provided by operating activities		741			37

Cash flows from investing activities
Capital expenditures		(704	)		(597	)
Changes in Exelon intercompany money pool contributions		—			308
Other investing activities		34			24

Net cash flows used in investing activities		(670	)		(265	)

Cash flows from financing activities
Changes in short-term debt		(306	)		146
Issuance of long-term debt		617			91
Retirement of long-term debt		(2	)		(310	)
Retirement of long-term debt to ComEd Transitional Funding Trust		(261	)		(278	)
Changes in Exelon intercompany money pool borrowings		(140	)		110
Dividends paid on common stock		—			(352	)
Contributions from parent		23			834
Other financing activities		(2	)		(5	)

Net cash flows provided by (used in) financing activities		(71	)		236

Increase in cash and cash equivalents		—			8
Cash and cash equivalents at beginning of period		38			30

Cash and cash equivalents at end of period	$	38		$	38

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,			December 31,
(In millions)	2006			2005

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	473		$	328
Long-term debt to ComEd Transitional Funding Trust due within one year		300			307
Accounts payable		213			223
Accrued expenses		456			417
Payables to affiliates		234			278
Commercial paper		153			459
Borrowing from Exelon intercompany money pool		—			140
Customer deposits		115			110
Other		62			46

Total current liabilities		2,006			2,308

Long-term debt		2,971			2,500
Long-term debt to ComEd Transitional Funding Trust		426			680
Long-term debt to other financing trusts		361			361
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,219			2,190
Asset retirement obligations		156			151
Non-pension postretirement benefit obligations		209			175
Regulatory liabilities		2,282			2,170
Other		295			280

Total deferred credits and other liabilities		5,161			4,966

Total liabilities		10,925			10,815

Commitments and contingencies
Shareholders’ equity
Common stock		1,588			1,588
Other paid-in capital		4,902			4,890
Retained deficit		(406	)		(81	)
Accumulated other comprehensive loss, net		(2	)		(1	)

Total shareholders’ equity		6,082			6,396

Total liabilities and shareholders’ equity	$	17,007		$	17,211

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						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,375		$	1,318		$	3,921		$	3,648
Operating revenues from affiliates		4			4			12			13

Total operating revenues		1,379			1,322			3,933			3,661

Operating expenses
Purchased power		82			71			224			181
Purchased power from affiliate		542			513			1,387			1,273
Fuel		42			42			445			373
Operating and maintenance		160			115			385			315
Operating and maintenance from affiliates		31			28			94			81
Depreciation and amortization		204			159			547			431
Taxes other than income		81			74			198			189

Total operating expenses		1,142			1,002			3,280			2,843

Operating income		237			320			653			818

Other income and deductions
Interest expense		(19	)		(15	)		(54	)		(41	)
Interest expense to affiliates, net		(47	)		(55	)		(148	)		(170	)
Equity in losses of unconsolidated affiliates		(2	)		(4	)		(7	)		(12	)
Other, net		11			2			16			10

Total other income and deductions		(57	)		(72	)		(193	)		(213	)

Income before income taxes		180			248			460			605
Income taxes		46			82			140			200

Net income		134			166			320			405
Preferred stock dividends		1			1			3			3

Net income on common stock	$	133		$	165		$	317		$	402

Comprehensive income, net of income taxes
Net income	$	134		$	166		$	320		$	405
Other comprehensive loss, net of income taxes
Change in net unrealized loss on cash-flow hedges		—			—			(1	)		(2	)

Other comprehensive loss		—			—			(1	)		(2	)

Comprehensive income	$	134		$	166		$	319		$	403

See the Combined Notes to Consolidated Financial Statements

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


	Nine Months Ended September 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	320		$	405
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		547			431
Deferred income taxes and amortization of investment tax credits		(182	)		(87	)
Other non-cash operating activities		77			51
Changes in assets and liabilities:
Accounts receivable		65			(4	)
Inventories		(17	)		(34	)
Accounts payable, accrued expenses and other current liabilities		(76	)		(56	)
Receivables from and payables to affiliates, net		(1	)		40
Income taxes		49			6
Pension and non-pension postretirement benefit contributions		(18	)		(164	)
Other assets and liabilities		42			3

Net cash flows provided by operating activities		806			591

Cash flows from investing activities
Capital expenditures		(241	)		(210	)
Changes in Exelon intercompany money pool contributions		8			34
Change in restricted cash		(1	)		27
Other investing activities		14			13

Net cash flows used in investing activities		(220	)		(136	)

Cash flows from financing activities
Issuance of long-term debt		303			—
Retirement of long-term debt		—			(15	)
Retirement of long-term debt to PECO Energy Transition Trust		(430	)		(361	)
Change in short-term debt		(220	)		—
Changes in Exelon intercompany money pool borrowings		—			7
Dividends paid on common and preferred stock		(371	)		(350	)
Contributions from parent		118			215

Net cash flows used in financing activities		(600	)		(504	)

Decrease in cash and cash equivalents		(14	)		(49	)
Cash and cash equivalents at beginning of period		37			74

Cash and cash equivalents at end of period	$	23		$	25

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,			December 31,
(In millions)	2006			2005

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Commercial paper	$	—		$	220
Long-term debt to PECO Energy Transition Trust due within one year		414			199
Accounts payable		122			182
Accrued expenses		84			92
Payables to affiliates		175			178
Customer deposits		56			54
Over-recovered energy costs		12			—
Other		8			11

Total current liabilities		871			936

Long-term debt		1,489			1,183
Long-term debt to PECO Energy Transition Trust		2,131			2,776
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,648			2,798
Asset retirement obligations		21			20
Non-pension postretirement benefit obligations		287			278
Other		146			139

Total deferred credits and other liabilities		3,102			3,235

Total liabilities		7,777			8,314

Commitments and contingencies
Shareholders’ equity
Common stock		2,223			2,193
Preferred stock		87			87
Receivable from parent		(1,126	)		(1,232	)
Retained earnings		598			649
Accumulated other comprehensive income, net		6			7

Total shareholders’ equity		1,788			1,704

Total liabilities and shareholders’ equity	$	9,565		$	10,018

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						Nine Months
	Ended September 30,						Ended September 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,186		$	1,207		$	3,318		$	3,047
Operating revenues from affiliates		1,449			1,504			3,751			3,789

Total operating revenues		2,635			2,711			7,069			6,836

Operating expenses
Purchased power		826			1,047			1,607			2,014
Fuel		447			441			1,484			1,227
Operating and maintenance		501			469			1,457			1,547
Operating and maintenance from affiliates		73			68			225			201
Depreciation and amortization		71			63			210			188
Taxes other than income		49			48			133			122

Total operating expenses		1,967			2,136			5,116			5,299

Operating income		668			575			1,953			1,537

Other income and deductions
Interest expense		(36	)		(33	)		(117	)		(89	)
Interest expense to affiliates, net		(2	)		—			(3	)		(2	)
Equity in earnings (losses) of unconsolidated affiliates		(5	)		(2	)		(9	)		2
Other, net		12			13			31			82

Total other income and deductions		(31	)		(22	)		(98	)		(7	)

Income from continuing operations before income taxes		637			553			1,855			1,530
Income taxes		244			219			696			595

Income from continuing operations		393			334			1,159			935

Discontinued operations
Loss from discontinued operations (net of taxes of $0 and $(1) for the three and nine months ended September 30, 2005, respectively)		—			—			—			—
Gain on disposal of discontinued operations (net of taxes of $0, $1, $2 and $5 for the three and nine months ended September 30, 2006 and 2005, respectively)		1			1			4			16

Income from discontinued operations, net		1			1			4			16

Net income		394			335			1,163			951

Other comprehensive income (loss), net of income taxes
Change in unrealized gain (loss) on cash-flow hedges		154			(181	)		386			(266	)
Unrealized gain (loss) on marketable securities		32			14			47			(10	)
Foreign currency translation adjustment		—			—			—			(1	)

Other comprehensive income (loss)		186			(167	)		433			(277	)

Comprehensive income	$	580		$	168		$	1,596		$	674

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine
	Months Ended
	September 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	1,163		$	951
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		694			661
Deferred income taxes and amortization of investment tax credits		129			378
Other non-cash operating activities		(31	)		(17	)
Changes in assets and liabilities
Accounts receivable		84			(73	)
Receivables from and payables to affiliates, net		149			(70	)
Inventories		10			(20	)
Accounts payable, accrued expenses and other current liabilities		(255	)		117
Counterparty collateral asset		236			(203	)
Counterparty collateral liability		159			104
Income taxes		(38	)		130
Net realized and unrealized mark-to-market and hedging transactions		(132	)		(139	)
Pension and non-pension postretirement benefit contributions		(25	)		(896	)
Other assets and liabilities		(255	)		(97	)

Net cash flows provided by operating activities		1,888			826

Cash flows from investing activities
Capital expenditures		(782	)		(704	)
Proceeds from nuclear decommissioning trust fund sales		3,584			3,234
Investment in nuclear decommissioning trust funds		(3,808	)		(3,387	)
Acquisitions of businesses, net of cash acquired		—			(97	)
Proceeds from sales of wholly owned subsidiaries, net of $32 of cash sold during the nine months ended September 30, 2005		—			103
Change in restricted cash		1			(1	)
Other investing activities		5			(4	)

Net cash flows used in investing activities		(1,000	)		(856	)

Cash flows from financing activities
Retirement of long-term debt		(12	)		(11	)
Change in short-term debt		(311	)		—
Changes in Exelon intercompany money pool borrowings		(86	)		(283	)
Distribution to member		(444	)		(749	)
Contribution from member		5			843
Other financing activities		(45	)		1

Net cash flows used in financing activities		(893	)		(199	)

Decrease in cash and cash equivalents		(5	)		(229	)
Cash and cash equivalents at beginning of period		34			263

Cash and cash equivalents at end of period	$	29		$	34

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,		December 31,
(In millions)	2006		2005

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Long-term debt due within one year	$	12	$	12
Accounts payable		728		954
Mark-to-market derivative liabilities		723		1,282
Payables to affiliates		60		4
Borrowings from Exelon intercompany money pool		6		92
Commercial paper		—		311
Accrued expenses		414		415
Other		342		330

Total current liabilities		2,285		3,400

Long-term debt		1,778		1,788
Deferred credits and other liabilities
Asset retirement obligations		3,551		3,986
Pension obligation		16		13
Non-pension postretirement benefit obligations		587		541
Spent nuclear fuel obligation		938		906
Deferred income taxes and unamortized investment tax credits		1,329		865
Payables to affiliates		1,732		1,503
Mark-to-market derivative liabilities		179		460
Other		250		280

Total deferred credits and other liabilities		8,582		8,554

Total liabilities		12,645		13,742

Commitments and contingencies
Minority interest of consolidated subsidiary		1		2
Member’s equity
Membership interest		3,266		3,220
Undistributed earnings		1,721		1,002
Accumulated other comprehensive income (loss), net		191		(242	)

Total member’s equity		5,178		3,980

Total liabilities and member’s equity	$	17,824	$	17,724

See the Combined Notes to Consolidated Financial Statements

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)


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

Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the energy delivery and generation businesses. The energy delivery businesses include the purchase and regulated retail and wholesale sale of electricity and 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 related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business consists principally of the electric generating facilities, wholesale energy marketing operations, competitive retail sales and certain other generation projects of Exelon Generation Company, LLC (Generation).

Exelon’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and its proportionate interests in jointly owned electric utility facilities, 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 method of accounting.

Exelon owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for less than 1% of ComEd’s common stock and all of PECO’s preferred stock. Exelon has reflected the third-party interests in ComEd and PECO as minority interest in its consolidated financial statements.

The accompanying consolidated financial statements as of September 30, 2006 and 2005 and for the three and nine months then ended are unaudited but, in the opinion of the management of each of Exelon, ComEd, PECO and Generation (collectively, the 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, 2005 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. Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or shareholders’ or member’s equity. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation included in ITEM 8 of their 2005 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 nine months ended September 30, 2006 and 2005 within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations and

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive Income. Results for the three and nine months ended September 30, 2005 related to these entities were as follows:


Three Months Ended September 30, 2005	Sithe(a)			Enterprises(b)		Total

Operating revenues	$	—		$	5	$	5
Operating income (loss)		—			—		—
Income before income taxes		2	(c)		—		2


(a)		Sithe was sold on January 31, 2005. Accordingly, there are no operating results for the three months ended September 30, 2005. See Note 4 — Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b)		Excludes certain investments.

(c)		Represents an adjustment to the gain on sale of Sithe as a result of the expiration of certain tax indemnifications, offset by accrued interest on certain indemnifications.


Nine Months Ended September 30, 2005	Sithe(a)			Enterprises(b)			Total

Operating revenues	$	30		$	14		$	44
Operating income (loss)		5			(4	)		1
Income (loss) before income taxes		20	(c)		(4	)		16


(a)		Includes Sithe’s results of operations from January 1, 2005 through January 31, 2005, which was the date of the sale. See Note 4 — Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b)		Excludes certain investments.

(c)		Sithe includes a pre-tax gain on sale of $21 million.

For the three months ended September 30, 2006, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income included $1 million of income (after-tax) from discontinued operations related to Sithe, which represented an adjustment to the gain on sale as a result of interest accrued on an indemnification and the collection of a receivable arising from the sale of Sithe. For the nine months ended September 30, 2006, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income included $4 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, accrued interest on an indemnification and the collection of a receivable arising from the sale of Sithe.


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

Exelon has identified the following new accounting pronouncements that either have been recently adopted or issued that may impact the Registrants upon adoption.

SFAS No. 123-R

Exelon grants stock-based awards through its Long-Term Incentive Plans (LTIPs), which primarily include stock options and performance share awards. Prior to January 1, 2006, Exelon accounted for these stock-based awards under the intrinsic value method of Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). This method under APB No. 25 resulted in no expense being recorded for stock option grants in 2005. On January 1, 2006, Exelon adopted Financial Accounting Standards Board (FASB) Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes APB No. 25. SFAS No. 123-R requires that compensation cost relating to stock-based payment transactions be recognized in the financial

statements. That cost is measured on the fair value of the equity or liability instruments issued. SFAS No. 123-R applies to all of Exelon’s outstanding unvested stock-based awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods. At September 30, 2006, there were approximately 28 million shares remaining for issuance under the LTIPs.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income during the three and nine months ended September 30, 2006 and 2005:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
Components of Stock-Based Compensation Expense	2006			2005			2006			2005

Stock options	$	7		$	—		$	32		$	—
Performance shares		21			15			62			38
Other stock-based awards		1			2			4			7

Total stock-based compensation included in operating and maintenance expense		29			17			98			45

Income tax benefit		(11	)		(7	)		(37	)		(18	)

Total after-tax stock-based compensation expense	$	18		$	10		$	61		$	27

The following table presents stock-based compensation expense (pre-tax) during the three and nine months ended September 30, 2006 and 2005:


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
Registrant	2006		2005		2006		2005

ComEd	$	2	$	1	$	9	$	1
PECO		1		—		2		1
Generation		11		4		37		16
Exelon Corporate(a)		15		12		50		27


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

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock are granted under the LTIPs. As a result of adopting SFAS No. 123-R, Exelon expensed $7 million and $32 million of stock options during the three and nine months ended September 30, 2006, respectively.

The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options granted under the LTIPs generally become exercisable upon a specified vesting date. Shares subject to stock options are typically issued from authorized but unissued common stock shares. All stock options expire 10 years from the date of grant. The vesting period of stock options outstanding as of September 30, 2006 generally ranged from 3 years to 4 years. The value of stock options at the date of grant is either amortized through expense or capitalized over the requisite service period using the straight-line method. For stock options granted to retirement eligible employees, the value of the stock option is recognized immediately on the date of

grant. There were no significant stock-based compensation costs capitalized during the three and nine months ended September 30, 2006 and 2005.

Exelon grants most of its stock options in the first quarter of each year. Stock options granted in the second and third quarter of 2006 and 2005 were not material.

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model with the following weighted average assumptions used for grants for the nine months ended September 30, 2006 and 2005:


	Nine Months
	Ended
	September 30,
	2006			2005

Dividend yield		3.2	%		3.6	%
Expected volatility		25.5	%		18.1	%
Risk-free interest rate		4.27	%		3.83	%
Expected life (years)		6.25			6.25

The dividend yield is based on several factors, including Exelon’s most recent dividend payment at the grant date and the average stock price over the previous twelve months. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. The expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified model. Additionally, Exelon uses historical data to estimate employee forfeitures. Exelon reviews the actual and estimated forfeitures and records an adjustment if necessary.

Utilizing the Black-Scholes-Merton option-pricing model and the assumptions discussed above, the weighted average grant-date fair value of stock options granted during the nine months ended September 30, 2006 and 2005 was $13.22 and $6.33, respectively.

Information with respect to stock options at September 30, 2006 is as follows:


				Weighted		Weighted
				Average		Average
				Exercise		Remaining		Aggregate
				Price		Contractual		Intrinsic
	Shares			(per share)		Life		Value

Balance of shares outstanding at December 31, 2005		21,674,270		$	31.23
Options granted		4,084,645			58.55
Options exercised		(4,811,395	)		28.78
Options forfeited/cancelled		(359,777	)		41.78

Balance of shares outstanding at September 30, 2006		20,587,743			37.02		7.00	$	484,187,746

Exercisable at September 30, 2006(a)		9,807,798			30.86		5.55		291,086,932


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

Intrinsic value for stock-based instruments is defined as the difference between the current market value and the exercise price. The total intrinsic value of stock options exercised during the three and nine months ended

September 30, 2006 was $44 million and $137 million, respectively, and $41 million and $165 million for the three and nine months ended September 30, 2005.

During the three and nine months ended September 30, 2006, cash received from stock options exercised was $38 million and $138 million, respectively, and the actual tax benefit realized for tax deductions from stock options exercised was $17 million and $55 million, respectively. During the three and nine months ended September 30, 2005, cash received from stock options exercised was $34 million and $184 million, respectively, and the actual tax benefit realized for tax deductions from stock options exercised was $16 million and $66 million, respectively. SFAS No. 123-R requires the benefits of tax deductions in excess of the compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. There was $43 million of excess tax benefits included as a cash inflow in other financing activities in Exelon’s Consolidated Statement of Cash Flow for the nine months ended September 30, 2006. Prior to the adoption of SFAS No. 123-R, Exelon presented these benefits as operating cash flows in the Consolidated Statement of Cash Flows.

The following table summarizes Exelon’s nonvested stock option activity for the nine months ended September 30, 2006:


				Weighted
				Average
				Exercise
				Price
	Shares			(per share)

Nonvested at December 31, 2005		12,000,284		$	35.42
Granted		4,084,645			58.55
Vested		(4,949,702	)		38.15
Forfeited		(355,282	)		43.06

Nonvested at September 30, 2006		10,779,945			38.99

As of September 30, 2006, $53 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2 years. The total grant date fair value of stock options vested, including the capitalized amount, during the three and nine months ended September 30, 2006 was $8 million and $34 million, respectively. The total grant date fair value of stock options vested during the three and nine months ended September 30, 2005 was $6 million and $18 million, respectively.

Performance Share Awards

In addition to the stock options discussed above, Exelon grants performance share awards under the LTIPs. These performance share awards will generally vest and settle over a three-year period. The holders of the performance share awards will receive shares of common stock and/or cash annually during the vesting period. The combination of common stock and/or cash is based on certain stock ownership requirements.

In January 2006, the Compensation Committee of the Board of Directors of Exelon granted 1,106,918 performance share awards, of which Exelon estimates that 601,306 will be settled in common stock and 505,613 will be settled in cash.

Performance share awards to be settled in stock are fair valued at the date of grant. Performance share awards to be settled in cash are remeasured each reporting period throughout the vesting period. As a result, the compensation costs for cash settled awards are subject to variability. The fair value of each performance share award granted during the nine months ended September 30, 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year. This model requires

assumptions regarding Exelon’s total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. Expected volatility is based on historical information. Additionally, Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted if necessary.

For non retirement-eligible employees, compensation costs are accrued and expensed over the vesting period of three years using the graded vesting method. As a result of adopting SFAS No. 123-R, Exelon recognizes ratably throughout the year of grant the entire compensation cost of new common stock awards in which retirement-eligible employees are fully vested in the year of grant (non-substantive vesting approach). Prior to the adoption of SFAS No. 123-R on January 1, 2006, such compensation cost was recognized over the nominal vesting period of performance with any remaining compensation cost recognized at the date of retirement. The impact of using the non-substantive vesting approach for retirement-eligible employees related to performance share awards was $3 million and $8 million during the three and nine months ended September 30, 2006, respectively. Exelon recognized compensation expense related to performance share awards (before income taxes) of $21 million and $62 million during the three and nine months ended September 30, 2006, respectively, and $15 million and $38 million during the three and nine months ended September 30, 2005, respectively. This compensation expense includes awards granted prior to 2006.

During the nine months ended September 30, 2006, Exelon settled 404,786 and 401,767 performance share awards in common stock and cash, respectively, related to awards granted prior to 2006.

At September 30, 2006, Exelon had an obligation related to outstanding awards not yet settled of $72 million, of which $32 million is included in common stock and $40 million is included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheet. At December 31, 2005, Exelon had an obligation related to outstanding awards not yet settled of $51 million, of which $27 million is included in common stock and $24 million is included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheet.

Other Stock-Based Awards

Exelon also issues common stock through an employee stock purchase plan and through restricted stock units and accounts for these awards in accordance with SFAS No. 123-R. The compensation cost of these types of issuances was immaterial during the three and nine months ended September 30, 2006 and 2005. However, at September 30, 2006 and December 31, 2005, Exelon had an obligation related to outstanding restricted stock not yet settled of $12 million and $19 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

Directors and executives are able to defer stock awards granted to them through Exelon’s stock-based compensation programs into the Exelon Corporation Stock Deferral Plan. At September 30, 2006 and December 31, 2005, Exelon had an obligation related to this plan of $37 million and $30 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

2005 Pro Forma Information

The table below shows the effect on Exelon’s net income and earnings per share had Exelon elected to account for all of its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three and nine months ended September 30, 2005:


	Three Months			Nine Months
	Ended			Ended
	September 30, 2005			September 30, 2005

Net income — as reported	$	725		$	1,760
Add: Stock-based compensation expense included in reported net income, net of income taxes		10			27
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes(a)		(14	)		(38	)

Pro forma net income	$	721		$	1,749

Earnings per share:
Basic — as reported	$	1.08		$	2.63
Basic — pro forma		1.08			2.61
Diluted — as reported		1.07			2.60
Diluted — pro forma		1.06			2.59


(a)		The fair value of stock options granted was estimated using a Black-Scholes-Merton option-pricing model.

Had Exelon recognized the entire compensation cost of its stock-based awards in which retirement-eligible employees were fully vested upon issuance for stock options, and in the first year for performance share awards (non-substantive vesting approach), as now required under SFAS No. 123-R, stock-based compensation expense would have been $2 million lower and $1 million higher after taxes than reflected in the table above for the three and nine months ended September 30, 2005, respectively. These pro forma amounts of $2 million and $1 million were calculated as if SFAS No. 123-R had always been implemented. However, at the time of adoption on January 1, 2006, the compensation cost of stock-based awards issued to retirement eligible employees was recognized using the non-substantive vesting approach prospectively.

SFAS No. 155

In February 2006, the FASB issued FASB Statement No. 155, “Accounting for Certain Hybrid Financial Instruments, amendment of FASB Statements No. 133 and 140” (SFAS No. 155). SFAS No. 155 gives entities the option of applying fair value accounting to certain hybrid financial instruments in their entirety if they contain embedded derivatives that would otherwise require bifurcation under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). SFAS No. 155 will be effective for the Registrants as of January 1, 2007 and the Registrants are currently assessing the impact that SFAS No. 155 may have on their financial statements.

SFAS No. 156

In March 2006, the FASB issued FASB Statement No. 156, “Accounting for Servicing of Financial Assets, amendment of FASB Statement No. 140” (SFAS No. 156). SFAS No. 156 amends SFAS No. 140 with respect to the accounting for separately recognized servicing assets and liabilities. SFAS No. 156 primarily requires companies to

initially record separately recognized servicing rights at fair value, allows companies to choose between two measurement methods and provides additional disclosure requirements. SFAS No. 156 will be effective for the Registrants as of January 1, 2007. The adoption of this standard is not expected to have a material impact to the Registrants.

FSP No. FIN 46(R)-6

In April 2006, the FASB issued FASB Staff Position No. FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP No. 46(R)-6). This pronouncement provides guidance on how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” which could impact the assessment of whether certain variable interest entities are consolidated. FSP No. 46(R)-6 was effective for the Registrants on July 1, 2006. The adoption of this standard did not have a material impact on the Registrants for the three months ended September 30, 2006. As the provisions of FSP No. 46(R)-6 are applied prospectively, the impact to the Registrants cannot be determined until the transactions occur.

FIN 48

In June 2006, the FASB issued 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 SFAS No. 109, “Accounting for Income Taxes.” 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 ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense 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. The change in net assets as a result of applying this pronouncement will be considered a change in accounting principle with the cumulative effect of the change treated as an offsetting adjustment to the opening balance of retained earnings or goodwill, if allowed under existing accounting standards, in the period of transition. FIN 48 is effective for the Registrants as of January 1, 2007 and the Registrants are currently assessing the impact that FIN 48 will have on their financial statements, which may be material. Two of Exelon’s and ComEd’s most significant uncertain tax positions relate to the 1999 sale of ComEd’s fossil generating assets are further described in Note 10 — Income Taxes.

EITF 06-3

In June 2006, the FASB ratified EITF Issue No. 06-3, “How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” (EITF 06-3). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 will be effective for the Registrants as of January 1, 2007. The Registrants disclose taxes that are imposed on and concurrent with a specific revenue-producing transaction in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Exelon’s, ComEd’s and PECO’s utility taxes are presented on a gross basis (see Note 15 — Segment Information). As

EITF 06-3 provides only disclosure requirements, the adoption of this standard is not expected to have a material impact on the Registrants.

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. 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. 158

In September 2006, the FASB issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). SFAS No. 158 requires Exelon to recognize the overfunded or underfunded status of its defined benefit postretirement plans as an asset or liability on its balance sheet. Had SFAS No. 158 been effective as of December 31, 2005, Exelon would have recorded an increase of approximately $2.2 billion to net pension and other postretirement benefits liabilities and a reduction of accumulated other comprehensive income within equity of up to $1.3 billion, net of income tax effects. SFAS No. 158 prescribes the measurement date of a plan to be the date of its year-end balance sheet, which is the measurement date Exelon already uses for its plans. Exelon will also be required to disclose additional information about certain effects on net periodic benefit cost for the next fiscal year. SFAS No. 158 will be effective for Exelon as of December 31, 2006. Exelon is currently assessing the impact that SFAS No. 158 will have on its financial statements, including whether a portion of the aggregate amounts recorded within accumulated other comprehensive income under SFAS No. 158 at the Exelon level may be recorded as a regulatory asset under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). The adoption of this standard is not expected to have a material impact on the Registrants’ debt or credit agreement covenants.

SAB No. 108

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB No. 108) regarding the quantification of financial statement misstatements. SAB No. 108 requires a “dual approach” for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years’ misstatements, and a method that focuses on the period-end balance sheet. SAB No. 108 will be effective for the Registrants as of January 1, 2007. The adoption of this standard is not expected to have a material impact on the Registrants.


4.	Acquisitions and Dispositions (Exelon and Generation)

Termination of Proposed Merger with PSEG (Exelon)

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would have been merged with and into Exelon (Merger). All regulatory approvals or reviews necessary to complete the Merger had been completed with the exception of the approval from the New Jersey Board of Public Utilities (NJBPU). On September 14, 2006, Exelon gave formal

notice to PSEG that Exelon had terminated the Merger Agreement and the companies agreed to withdraw their application for Merger approval, which had been pending before the NJBPU for more than 19 months. Exelon also terminated pending dockets and/or appeals in numerous other jurisdictions, including before the Federal Energy Regulatory Commission (FERC) and the Antitrust Division of the United States Department of Justice. See Note 5 — Regulatory Issues for information regarding PECO’s settlement before the Pennsylvania Public Utility Commission (PAPUC).

Exelon capitalized certain external costs associated with the Merger since the execution of the Merger Agreement on December 20, 2004. As required under GAAP, Exelon recorded a charge of approximately $55 million ($35 million after tax) in operating and maintenance expense on Exelon’s Consolidated Statement of Operations in the third quarter of 2006 to write off the capitalized costs associated with the Merger. Including this $55 million write-off of capitalized costs, total merger-related costs and expenses incurred since the inception of the Merger discussions were approximately $130 million. Total capitalized costs of $46 million were included in deferred debits and other assets on Exelon’s Consolidated Balance Sheets as of December 31, 2005.

See Note 3 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for additional information regarding the Merger.

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 closed on the acquisition of Reservoir Capital Group’s (Reservoir) 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy).

In connection with the sale, Exelon recorded $55 million of liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. Generation issued certain guarantees associated with income tax indemnifications to Dynegy in connection with the sale that were valued at approximately $8 million (included in the $55 million accrual discussed above), of which $7 million has expired as of September 30, 2006. These 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” (FIN 45). The exposures covered by these indemnities are anticipated to expire in 2006 and beyond. These liabilities were taken into account in the determination of the net gain on the sale of $21 million (before income taxes), which was subsequently adjusted to $24 million (before income taxes) as of December 31, 2005. As of September 30, 2006, Exelon’s accrued liabilities related to these indemnifications and guarantees were $41 million, including $1 million related to income tax indemnifications. The net decrease for the accrual initially established was due to the expiration of certain guarantees, tax indemnifications and accrued interest on certain indemnifications. 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 September 30, 2006.

Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2005 included the following financial results related to Sithe, which were presented as discontinued operations:


	Three Months		Nine Months
	Ended		Ended
	September 30, 2005(a)		September 30, 2005(b)

Operating revenues	$	—	$	30
Operating income		—		5
Net income		1		16	(c)


(a)		Sithe was sold on January 31, 2005. Accordingly, there are no operating results for the three months ended September 30, 2005.

(b)		Sithe was sold on January 31, 2005. Accordingly, results include only one month of operations.

(c)		Includes a pre-tax gain on sale of Sithe of $21 million.

Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2006 included a $1 million and $4 million (after-tax) gain, respectively, as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe.

See Note 3 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for further discussion of Generation’s investment in Sithe.


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

The legislatively mandated transition and rate freeze period in Illinois is scheduled to conclude on January 1, 2007. Associated with the end of this rate freeze, ComEd is engaged in various regulatory and legislative proceedings to establish rates for the post-2006 period, which are more fully described below.

Illinois Procurement Filing (Exelon and ComEd). On February 25, 2005, ComEd made a filing with the Illinois Commerce Commission (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 January 24, 2006, the ICC, by a unanimous vote, approved the tariffs for the period commencing January 2, 2007. The reverse-auction competitive bidding process is administered by an independent auction manager, with oversight by the ICC staff. In order to mitigate the effects of changes in future prices, electricity to serve residential and commercial customers with loads less than 400kW will be procured through staggered three-year contracts.

The ICC will subsequently review on an annual basis the prudence of ComEd’s electricity purchases but compliance with the ICC-approved reverse auction process will establish a rebuttable presumption of prudence. Various parties, including governmental and consumer representatives and ComEd, have filed petitions for review of portions of the order with the Illinois Appellate Court. While ComEd is generally supportive of the order in the Procurement Case, ComEd has objected to the requirement for an after-the-fact prudence review. On June 2, 2006, the Illinois Attorney General filed a petition with the Illinois Supreme Court asking the Supreme Court to hear the matter on direct appeal, to grant expedited review of the pending appeals, and to stay implementation of the auction pending appeal. On August 4, 2006, the Illinois Supreme Court denied this petition. The Illinois Attorney General filed a petition with the Illinois Appellate Court asking for a stay of implementation of the ICC order in the Procurement Case pending the Illinois Appellate Court’s decision on the appeals. That request was denied on August 23, 2006. The appeals before the Illinois Appellate Court are still pending.

Initial ComEd Auction (Exelon and ComEd). The first procurement auction for ComEd’s entire load took place during September 2006. It was for electricity that would be delivered beginning in January 2007. Auction participants bid on several different products including 17-, 29- and 41-month contracts that will be “blended” together and used to serve residential and small commercial customers, a 17-month product that would be used to serve larger non-residential customers, and a variably priced (hourly) product that will be used to serve customers who select hourly service. The ICC accepted the auction results related to the blended and annual products but rejected the auction results of the variable (hourly) product. Under ComEd’s tariffs, electricity that would have been procured through the variable (hourly) auction will be purchased in PJM-administered markets.

Based on the requirements approved by the ICC, the amounts won by each participant in the auction will not be made public until December 1, 2006. ComEd has entered into supplier forward contracts with all of those who have won shares of the ComEd products through the auction. Suppliers were limited to winning no more than 35% in either the fixed price section or the hourly price section of the auction. The following table shows the clearing prices for each product set in the first auction:


	Price per MWh
Product	17 Month Contract		29 Month Contract		41 Month Contract

Annual	$	90.12		N/A		N/A
Blended	$	63.96	$	64.00	$	63.33

The next auction is scheduled for February 2008 for the period June 2008 through May 2009 (and up to May 2011 for portions of the blended product). Auctions will be held annually thereafter covering the next June to May twelve-month and thirty-six-month periods.

See Note 10 — Income Taxes — Impact of Illinois Auction on State Income Taxes for additional information on the impact of the auction.

Rate Freeze Extension Proposal (Exelon and ComEd). On February 24, 2006, House Bill 5766 (HB 5766) was introduced in the Illinois General Assembly and was referred to the Rules Committee. HB 5766, if enacted, would extend the current rate freeze in Illinois until at least 2010. The Illinois General Assembly took no action on the bill and is now adjourned. It is scheduled to resume session in November 2006. However, the Speaker of the Illinois House of Representatives (House) has requested the Governor to call a special session of the General Assembly to enact legislation identical in substance to HB 5766. The Governor has indicated he will call a special session if the required votes for passing rate freeze legislation are assured. On October 9, 2006, an amendment was filed to Senate Bill 1714 (SB 1714), which is substantively the same as HB 5766. Also on October 9, 2006, the House Electric Utility Oversight Committee, by a 9 to 4 vote, with one member voting present, approved the amendment to SB 1714. Legislation still needs to be passed by both the House and the Senate and be signed by the Governor. In order for the legislation to be effective January 2007, a three-fifths vote is required in both the House and Senate. ComEd is unable to predict the final disposition of HB 5766, SB 1714 or other potential legislation to change the end of the mandated transition and rate freeze period in Illinois. ComEd believes the proposed legislation, if enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. See “Post 2006 Summary” below for further detail. ComEd believes the proposed rate freeze extension, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such enacted rate freeze legislation in court.

Residential Rate Stabilization Program (Exelon and ComEd). In 2006, ComEd filed a proposal with the ICC to mitigate the impact of the transition to the post rate-freeze period on its residential customers. ComEd’s current proposal, including modifications agreed to during the course of the proceeding, includes an “opt-in” feature to give residential customers the choice to participate in the program. Average annual residential rate

increases would be capped at 10% in 2007, 2008 and 2009 for customers choosing to participate in the program. For those customers, costs that exceed the caps would be deferred and recovered with ComEd’s carrying charges of 6.5% over three years from 2010 to 2012. 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 plan would terminate upon a force majeure event, upon a ComEd bankruptcy, or if ComEd’s senior unsecured credit rating from at least one of the three major credit rating agencies falls below investment grade. The ICC staff, the Illinois Attorney General and collectively the City of Chicago, Citizens Utility Board and Cook County States Attorney’s Office filed testimony objecting to all or parts of the proposal. A decision in the proceeding is expected in November 2006. Although the action by Standard and Poor’s Corporation (S&P) on October 5, 2006 to lower ComEd’s senior unsecured credit ratings to below investment grade would, if the program were in effect, result in termination of the program, ComEd has asked the ICC to continue to consider the proposal because S&P has indicated it may reevaluate its ratings on ComEd if no rate freeze legislation is passed. On October 20, 2006, the administrative law judge (ALJ) reviewing the residential rate stabilization program issued a proposed order which is consistent with ComEd’s proposal for this program. However, the ultimate outcome is uncertain pending the final ICC order and the status of ComEd’s credit ratings

Illinois Rate Case (Exelon and ComEd). On August 31, 2005, ComEd filed a rate case with the ICC to comprehensively review its tariff and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate 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. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC rate order in the Procurement Case. On June 8, 2006, the ALJs issued a proposed order, which included a revenue increase of $164 million plus ComEd’s request for recovery of several items which previously were recorded as expense. On July 26, 2006, the ICC issued its order in the Rate Case which approved a delivery services revenue increase of $8 million. The ICC order did approve ComEd’s requested recovery of several items which previously were recorded as expense. However, the ICC disallowed rate base treatment (return) for ComEd’s prepaid pension asset, net of deferred taxes, of $639 million and disallowed the recovery of certain administrative and general expenses. These disallowances will not result in an immediate write-off since the prepaid pension asset should be recovered as pension cost is recognized and recovered from customers in the future but will reduce ComEd’s future return on equity until the asset is recovered. The ICC rate order also provided for lower returns on rate base than ComEd had requested. See Note 13 — Commitments and Contingencies for further information. On August 30, 2006, the ICC granted in part, and denied in part, ComEd’s request for rehearing. Other parties also filed requests for rehearing which were granted in part and denied in part. Items to be considered in the rehearing include administrative and general expenses, general and intangible plant, prepaid pension asset, capital structure, the allowed return on equity and certain rate design issues. The rehearing process may take up to five months to complete although the current schedule indicates that the rehearing may be completed before the end of 2006. ComEd or any other party may appeal the Rate Case if it is not satisfied with the results on rehearing. ComEd intends to do so if disallowances contained in the ICC’s original order are not changed on rehearing. If an appeal of the Rate Case is successful, any resulting adjustments to ComEd’s rates would have only a prospective effect and would not be retroactive.

Original Cost Audit (Exelon and ComEd). In the Rate Case, the ICC, with ComEd’s concurrence, ordered an “original cost” audit of ComEd’s distribution assets. There was no suggestion in the Rate Case that any specific asset 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 will determine whether the costs of ComEd’s distribution assets were properly recorded on ComEd’s financial statements at their original costs. This will be completed through a separately docketed proceeding. The original

cost audit is not expected to be finalized in 2006. ComEd is unable to predict the results of this audit but does not believe the results of the audit will have a material impact on ComEd’s financial position or results of operations.

Customers’ Affordable Reliable Energy (Exelon and ComEd). In July 2006, ComEd implemented Customers’ Affordable Reliable Energy (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 proposal, CARE includes a variety of energy efficiency, low-income and senior citizen programs to help mitigate the impacts of the anticipated rate increase on customers’ bills. ComEd estimates spending approximately $10 million for CARE in 2006 and has spent $7 million through September 30, 2006.

Renewable Energy Filings (Exelon and ComEd). The ICC, in a January 24, 2006 order, ordered its staff to initiate three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources. These rulemakings have proceeded with ComEd’s active participation. However, on October 12, 2006 the ICC voted 5 to 0 to dismiss the ICC’s rulemaking proceedings for demand response programs, energy efficiency programs and renewable energy sources.

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 MW. The filing supports the ICC’s resolution of July 19, 2005 which endorsed the Illinois Governor’s proposal for a voluntary initiative in which electric suppliers would obtain resources equal to 2% of electricity sold to Illinois retail customers from renewable energy resources by the end of 2007 and gradually increasing to a target of 8% by 2013. This filing covers the first year’s wind-only procurement associated with the Illinois Governor’s proposal. ComEd asked, and the ALJ agreed, to continue these proceedings until February 2007. Actual purchase of wind resources is contingent upon an ICC order approving the prudence of this activity and authorizing cost recovery.

ComEd may file additional demand response, energy efficiency and renewable energy related initiatives in the future; however, such initiatives will likely be dependent on the resolution of other regulatory issues mentioned previously.

Post 2006 Summary (Exelon and ComEd). ComEd cannot predict the results of any rehearings or appeals in the Rate Case or the Procurement Case or whether the Illinois General Assembly might pass HB 5766 or SB 1714 or other action that could have a material effect on the outcome of the regulatory process. However, if the price which ComEd is ultimately allowed to bill to customers for electricity beginning in 2007 is below ComEd’s cost to procure and deliver electricity, ComEd expects that it will 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 nearer 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, which covers the accounting for the effects of rate regulation and which 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 (Loss). At September 30, 2006, the

income statement credit could have been as much as $2.3 billion (before taxes). Exelon would record an income statement credit in an equal amount related to ComEd’s regulatory assets and liabilities. Finally, the impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which would be significant and at least partially offset the extraordinary gain discussed above. See Note 6 — Intangible Assets for further information related to ComEd’s goodwill.

Partial Settlement before the PAPUC (Exelon and PECO). As a result of the termination of the Merger Agreement, the provisions of the PAPUC order and partial settlement approving the Merger will not become effective and will not be applicable to PECO or the other parties to the settlement. See Note 4 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for further discussion.

Through and Out Rates/SECA (Exelon, ComEd and PECO). In November 2004, the 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 through and out (T&O) rates for transmission service scheduled out of, or across, their respective transmission systems and ending within pre-expansion territories of PJM Interconnection, LLC (PJM) or Midwest Independent System Operators (MISO). T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), were collected from load-serving entities 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 receive 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, including $5 million during the nine months ended September 30, 2006, while PECO has recorded $10 million of SECA charges net of SECA collections, including $3 million during the nine months ended September 30, 2006. 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. Hearings and briefing of the matter have been concluded and an initial decision of the presiding ALJ was issued on August 10, 2006. The ALJ’s initial decision indicated 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. FERC will determine whether or not to accept the ALJ’s recommendation. There is no timeline for FERC to act on this matter. Meanwhile, settlements have been reached with various parties. FERC has approved several of these settlements while others are still awaiting final execution and/or FERC approval. The ultimate outcome of the proceeding establishing SECA rates is uncertain.

PJM Transmission Design (Exelon, ComEd and PECO). On May 31, 2005, the FERC issued an order creating an evidentiary hearing process to examine the existing PJM transmission rate design. A number of parties submitted testimony proposing the replacement of that rate design for existing facilities with several variations which could have an adverse impact on Exelon’s pre-tax operating income. FERC staff submitted testimony opposing adoption of all of those variations, and in the alternative recommended that the FERC supplant the existing design in which customers in a zone pay a transmission rate based on the cost of transmission in that zone, with a postage stamp rate design across PJM in which a single, uniform charge would be applied for all existing transmission facilities. This proposal, if adopted, would also be expected to produce an adverse impact on Exelon’s pre-tax operating income. ComEd and PECO, as members of the Responsible Pricing Alliance (comprised of most of the PJM transmission owners), submitted testimony opposing all changes and urging retention of the existing rate design at least through January 2008.

On July 13, 2006, the ALJ in the case issued an initial decision that recommends that the 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 review of the matter, the FERC will determine whether changes in rate design should be made, what those changes should be and their effective date. There is no set timeline for the FERC to act on this matter. ComEd and PECO cannot predict how the FERC will ultimately rule on this matter, including the effective date and if there would be any rates that may be subject to refund. ComEd and PECO also cannot estimate the final impact on either company’s results of operations and cash flows. However, ComEd anticipates that, with the completion of the rate freeze at the end of this year, barring an extension of the freeze beginning in 2007, all impacts of any rate design changes effective after December 31, 2006 should be recoverable through retail rates.

Initial Illinois Auction (Exelon and Generation). As described in the “Initial ComEd Auction” section above, Generation participated and won portions of the ComEd and Ameren Corporation (Ameren) auctions. Based on the requirements of the ICC, the final results of the auction will not be made public until December 1, 2006. The clearing prices for the ComEd auction are described above, while the clearing prices for the Ameren auction were as follows:


	Price per MWh
Product	17 Month Contract		29 Month Contract		41 Month Contract

Annual	$	84.95		N/A		N/A
Blended	$	64.77	$	64.75	$	66.05

Post 2006 Summary (Exelon and Generation). Generation’s purchased power agreement (PPA) with ComEd expires at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation will sell more power at market-based rates through supplier forward contracts with ComEd and Ameren and bilateral agreements with other new and existing counterparties. 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 is anticipated to change based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the proposed rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of power. A default by ComEd or Ameren on contracts for purchase of power, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets.

Market-Based Rates Filing (Exelon and Generation). On April 3, 2006, FERC accepted Exelon’s compliance filings regarding its triennial update of market-based rates and terminated proceedings under Section 206 of the Federal Power Act. FERC had initiated Section 206 proceedings based upon its initial understanding that Exelon had not addressed the affiliate abuse and reciprocal dealing component of FERC’s market-power analysis. In the order, FERC accepted Exelon’s statements that, under the regulatory structures in Illinois and Pennsylvania, most of the load is served under fixed prices, a scenario that has not changed since the previous market-based rates filing in 2000. FERC agreed that these pricing structures alleviated any concerns of affiliate abuse or reciprocal dealing. For a further discussion of this matter, see Note 4 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K.

Notice of Proposed Rulemaking (NOPR) on Market-Based Rate Authority (Exelon and Generation). With the expiration of the PPA between Generation and ComEd on December 31, 2006 and the commencement of sales by Generation to ComEd under a new supplier forward contract on January 1, 2007 as a result the Illinois procurement auction, the amount of power sold forward by Generation under contracts with terms of one year or more will initially decrease but may also increase over time as Generation continues to sell power under long-term

contracts. Long-term sales of a year or more are relevant for purposes of FERC granting Generation authority to sell power at market-based rates. Exelon does not believe the initial decrease in long-term sales will affect Exelon’s authority to sell at market-based rates under the current tests applied by FERC. On May 19, 2006, FERC issued a NOPR on Market-Based Rate Authority, to address regulations on the granting of market-based rates, the structure of market power screens for purposes of granting market-based rates and the structure of market-based rates tariffs. There is no timetable for FERC to adopt a rule pursuant to the NOPR nor any assurance that any such rule will be adopted or what the effect of any such rule would be on Exelon’s authority to sell power at market-based rates.


6.	Intangible Assets (Exelon and ComEd)

Goodwill (Exelon and ComEd). As of September 30, 2006 and December 31, 2005, Exelon and ComEd had goodwill of approximately $2.7 billion and $3.5 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. However, due to the significant negative impact of the ICC’s order in ComEd’s Rate Case to the future cash flows and value of ComEd, an interim impairment assessment was required during the third quarter of 2006. Based on the results of ComEd’s interim goodwill impairment analysis, Exelon and ComEd recorded an impairment charge of $776 million associated with the write-off of the goodwill. Future developments relating to ComEd’s ongoing regulatory and/or legislative items could also be relevant to future goodwill impairment analyses and may lead to further impairments, which could be material. See Note 5 — Regulatory Issues for further information regarding the Rate Case and the Procurement Case. See Note 10 — Income Taxes for the income tax implications.

The changes in the carrying amount of goodwill for the period from January 1, 2006 to September 30, 2006 were as follows:


Balance as of January 1, 2006	$	3,475
Resolution of certain tax matters(a)		(5	)
Impairment		(776	)

Balance as of September 30, 2006	$	2,694


(a)		Adjustment related to income tax refund claims and interest thereon, and various deferred tax adjustments. See Note 13 — Commitments and Contingencies for further information.

Other Intangible Assets (Exelon). Exelon’s other intangible assets, included in deferred debits and other assets, consisted of the following:


	September 30, 2006						December 31, 2005
			Amortization						Accumulated
Exelon	Gross		Accumulated		Net		Gross		Amortization			Net

Synthetic fuel investments(a)	$	—	$	—	$	—	$	264	$	(121	)	$	143
Intangible pension asset		34		—		34		34		—			34

Total intangible assets	$	34	$	—	$	34	$	298	$	(121	)	$	177


(a)		See Note 3 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for a description of Exelon’s right to acquire tax credits through investments in synthetic fuel-producing facilities. In the second quarter of 2006, Exelon recorded an impairment charge of $115 million (before income taxes) associated with the full write-

off of the intangible asset related to its investment in synthetic fuel-producing facilities. See Note 10 — Income Taxes for further discussion.

For the three and nine months ended September 30, 2006, Exelon’s amortization expense related to intangible assets was $0 million and $28 million, respectively. For the three and nine months ended September 30, 2005, Exelon’s amortization expense related to intangible assets was $16 million and $52 million, respectively.


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

Commercial Paper and Notes Payable

Exelon, ComEd, PECO and Generation meet their short-term liquidity requirements primarily through the issuance of commercial paper. Exelon, ComEd, PECO and Generation had the following amounts of commercial paper outstanding at September 30, 2006 and December 31, 2005:


	September 30,		December 31,
Borrower	2006		2005

Exelon Corporate	$	—	$	—
ComEd		153		459
PECO		—		220
Generation		—		311

On July 31, 2006, Exelon amended its $300 million term loan agreement to extend the maturity date to the earlier of December 31, 2006 or the effective date of Exelon’s new credit facilities, which is expected by October 31, 2006.

Credit Facilities

As of September 30, 2006, Exelon, PECO and Generation participated with a group of banks in a $1 billion unsecured revolving credit facility maturing on July 16, 2009 and a $500 million unsecured revolving credit facility maturing on October 31, 2006. These agreements were amended on February 22, 2006 to remove ComEd as a borrower and to remove provisions that would treat ComEd as a significant subsidiary of Exelon for purposes of its covenants and defaults under the credit agreements. See Note 10 of Exelon’s 2005 Annual Report on Form 10-K for further information regarding these credit facilities. In addition to these credit facilities, during 2006, Generation and ComEd each executed new credit facility agreements which are described below. The Registrants may use the credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. The obligation of each lender to make any credit extension to a Registrant under its credit facilities is subject to various conditions including, among other things, that no event of default has occurred for the Registrant or would result from such credit extension. A bankruptcy filing by ComEd would constitute an event of default under ComEd’s credit facilities; however, bankruptcy or another event of default by ComEd would not constitute an event of default for Exelon, Generation or PECO.

Generation

On February 10 through 16, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $950 million. On September 19, 2006, Generation entered into three separate revolving credit facilities with aggregate bank commitments of $1 billion. The additional credit facilities are each for a term of 364 days after the effective date of the facility or earlier upon the effective date of substitute credit facilities and contain or incorporate by reference the terms within the revolving credit facilities described in Note 10 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K.

ComEd

On February 22, 2006, ComEd entered into a $1 billion senior secured three-year revolving credit agreement. The credit agreement is secured by First Mortgage Bonds of ComEd in the principal amount of approximately $1 billion. First Mortgage Bonds are a first mortgage lien on ComEd’s utility assets other than expressly excepted property.

Issuance of Long-Term Debt

During the nine months ended September 30, 2006, the following long-term debt was issued:


		Interest
Company	Type	Rate	Maturity	Amount(a)

ComEd	First Mortgage Bonds	5.90%	March 15, 2036	$	325
ComEd	First Mortgage Bonds	5.95%	August 15, 2016		300
PECO	First Mortgage Bonds	5.95%	October 1, 2036		300
Other	Various	Various	Various		7


(a)		Excludes unamortized bond discounts.

Retirement of Long-Term Debt

During the nine months ended September 30, 2006, 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	$	50
ComEd	ComEd Transitional Funding Trust	5.63%	June 25, 2007		261
PECO	PECO Energy Transition Trust (PETT)	6.05%	March 1, 2007		430
Generation	Notes payable	6.33%	August 8, 2009		10
Other	Various	Various	Various		4

SCEP

Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of Southeast Chicago Energy Project, LLC (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. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a 20-year period. Generation had reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements.

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.


8.	Severance Benefits (Exelon, ComEd, PECO and Generation)

Following the termination of the proposed Merger, Exelon has evaluated its organizational structure and resource needs on a standalone basis (see Note 4 — Acquisitions and Dispositions for further information on the

Merger termination). As a result of that evaluation, management has concluded that certain positions will be eliminated. Therefore, Exelon recorded $23 million of severance charges in the third quarter of 2006. The following tables present total salary continuance severance costs (benefits), recorded as operating and maintenance expense, for the three and nine months ended September 30, 2006 and 2005:


Salary Continuance Severance Costs	ComEd		PECO		Generation			Other(a)			Exelon

Expense recorded for the three months ended September 30, 2006	$	3	$	2	$	6		$	12		$	23
Expense recorded for the nine months ended September 30, 2006		1		2		7	(c)		14	(b)		24	(b),(c)


(a)		Other includes corporate operations and shared service entities, including Exelon Business Services Company (BSC).

(b)		Includes $2 million of severance related to stock-based compensation, which is not included in the salary continuance severance obligations table below.

(c)		Excludes reduction of previously recorded severance charges of approximately $1 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG.


Salary Continuance Severance Costs	ComEd			PECO		Generation			Other(a)			Exelon

Expense (income) recorded for the three months ended September 30, 2005	$	(5)		$	—	$	(2)		$	(2)		$	(9	)
Expense (income) recorded for the nine months ended September 30, 2005		(8	)		1		(4	)		(1	)		(12	)


(a)		Other includes corporate operations and shared service entities, including BSC.

The following table presents the activity of the salary continuance severance obligations from January 1, 2006 through September 30, 2006:


Salary Continuance Obligations	ComEd			PECO			Generation			Other(a)			Exelon

Balance at January 1, 2006	$	8		$	1		$	7		$	6		$	22
Severance charges recorded		1			2			7			12			22
Cash payments		(2	)		(1	)		(2	)		(3	)		(8	)

Balance at September 30, 2006	$	7		$	2		$	12		$	15		$	36


(a)		Other includes corporate operations and shared service entities, including BSC and Enterprises.

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

The following tables present the components of Exelon’s net periodic benefit costs for the three and nine months ended September 30, 2006 and 2005. The 2006 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 9.00%. The 2006 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 8.17%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.


							Other
	Pension						Postretirement
	Benefits						Benefits
	Three Months						Three Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

Service cost	$	39		$	32		$	25		$	20
Interest cost		141			132			46			45
Expected return on assets		(205	)		(190	)		(26	)		(25	)
Amortization of:
Transition obligation (asset)		—			(1	)		2			2
Prior service cost (benefit)		4			4			(22	)		(23	)
Actuarial loss		38			30			21			28

Net periodic benefit cost	$	17		$	7		$	46		$	47


	Pension						Other
	Benefits						Postretirement
	Nine Months						Benefits
	Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005

Service cost	$	118		$	108		$	75		$	67
Interest cost		422			410			137			131
Expected return on assets		(613	)		(576	)		(79	)		(74	)
Amortization of:
Transition obligation (asset)		—			(3	)		7			7
Prior service cost (benefit)		12			12			(68	)		(68	)
Actuarial loss		112			91			65			61

Net periodic benefit cost	$	51		$	42		$	137		$	124

The following table presents the allocation of Exelon’s pension and postretirement benefit costs during the three and nine months ended September 30, 2006 and 2005:


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
Pension and Postretirement Benefit Costs(a)	2006		2005		2006		2005

ComEd	$	18	$	8	$	54	$	46
PECO		7		11		22		22
Generation		28		24		85		73
Exelon Corporate(b)		10		11		27		25


(a)		Includes capitalized costs and operating and maintenance expense.

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

Exelon sponsors savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon matches 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 nine months ended September 30, 2006 and 2005:


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
Savings Plan Matching Contributions	2006		2005		2006		2005

Exelon	$	15	$	15	$	45	$	44
ComEd		5		4		13		12
PECO		2		2		5		5
Generation		7		7		23		21

In the third quarter of 2006, President Bush signed into law the Pension Protection Act of 2006, which will affect the manner in which many companies, including Exelon, administer their pension plans. This legislation will 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. This legislation will be effective for the Registrants as of January 1, 2008 and the Registrants are currently assessing the impact that it may have on their financial statements.

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

Exelon

Exelon’s effective income tax rate from continuing operations varied from the U.S. Federal statutory rate principally due to the following:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
Non-deductible goodwill impairment charge		84.6			—			14.1			—
State income taxes, net of Federal income tax benefit		10.1			4.3			4.6			3.9
Qualified nuclear decommissioning trust fund income		1.1			0.3			0.5			0.5
Synthetic fuel-producing facilities credit(a)		(8.9	)		(6.6	)		(2.8	)		(7.5	)
Domestic production activities deduction		(1.8	)		(0.5	)		(0.8	)		(0.4	)
Tax exempt income		(0.9	)		(0.2	)		(0.4	)		(0.3	)
Amortization of investment tax credit		(0.9	)		(0.2	)		(0.5	)		(0.3	)
Nontaxable postretirement benefits		(0.8	)		(0.4	)		(0.4	)		(0.3	)
Other		(3.5	)		0.5			(1.1	)		0.2

Effective income tax rate		114.0	%		32.2	%		48.2	%		30.8	%


(a)		See Notes 3 and 12 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for further information regarding investments in synthetic fuel-producing facilities.

ComEd

ComEd’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

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		(6.5	)		4.8			(145.3	)		4.8
Amortization of regulatory asset		(0.8	)		0.7			(19.4	)		0.7
Nontaxable postretirement benefits		0.2			(0.2	)		7.9			(0.3	)
Amortization of investment tax credit		0.2			(0.2	)		8.6			(0.3	)
Non-deductible goodwill impairment charge		(82.7	)		—			(1,094.9	)		—
Other		0.8			0.8			8.1			0.5

Effective income tax rate		(53.8	)%		40.9	%		(1,200.0	)%		40.4	%

PECO

PECO’s effective income tax rate varied from the U.S. Federal statutory rate principally due to the following:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

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		(2.4	)		0.5			(1.8	)		(0.8	)
Plant basis differences		0.7			(0.5	)		0.6			(0.3	)
Nontaxable postretirement benefits		(0.2	)		(0.2	)		(0.2	)		(0.2	)
Amortization of investment tax credit		(0.3	)		(0.2	)		(0.4	)		(0.3	)
Investment tax credit refund(a)		(7.2	)		—			(2.8	)		—
Other		—			(1.5	)		—			(0.3	)

Effective income tax rate		25.6	%		33.1	%		30.4	%		33.1	%


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

Generation

Generation’s effective income tax rate from continuing operations varied from the U.S. Federal statutory rate principally due to the following:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

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			5.1			4.1			4.8
Qualified nuclear decommissioning trust fund income		0.6			0.6			0.5			0.9
Domestic production activities deduction		(0.9	)		(1.0	)		(0.8	)		(0.6	)
Tax exempt income		(0.5	)		(0.5	)		(0.5	)		(0.5	)
Nontaxable postretirement benefits		(0.2	)		(0.3	)		(0.2	)		(0.3	)
Amortization of investment tax credit		(0.2	)		(0.2	)		(0.2	)		(0.2	)
Investment tax credit charge(a)		1.5			—			0.5			—
Other		(0.6	)		0.9			(0.9	)		(0.2	)

Effective income tax rate		38.3	%		39.6	%		37.5	%		38.9	%


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

Tax Sharing Agreement (ComEd, PECO and Generation)

ComEd, PECO and Generation are all party to an agreement (Tax Sharing Agreement) with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit. As of September 30, 2006, ComEd, PECO and Generation have recorded an allocation of tax benefits from Exelon under the Tax Sharing Agreement of $17 million, $30 million and $46 million, respectively. Exelon paid $10 million, $27 million and $18 million of these amounts to ComEd, PECO and Generation, respectively, in October 2006. See Note 16 — Related-Party Transaction for additional information.

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 that own synthetic fuel-producing facilities. Section 45K (formerly Section 29) of the Internal Revenue Code (IRC) 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. On April 11, 2006, the Internal Revenue Service (IRS) published the 2005 oil Reference Price and it did not exceed the beginning of the phase-out range. Consequently, there was no phase-out of tax credits for calendar year 2005.

The following table (in dollars) provides the estimated phase-out range for 2006 based on the per barrel price of oil as of September 30, 2006. The table also contains the estimated 2006 annual average New York Mercantile Exchange, Inc. index (NYMEX) price per barrel at September 30, 2006 based on year-to-date and futures prices.


	Estimated
	2006

Beginning of Phase-Out Range(a)	$	60
End of Phase-Out Range(a)		76
2006 Annual Average NYMEX		67


(a)		The estimated 2006 phase-out range is based upon the actual 2005 phase-out range. The actual 2005 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2006. The actual 2005 phase-out range was increased by 2% (Exelon’s estimate of inflation) to arrive at the estimated 2006 phase-out range.

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to suspend synthetic fuel production was primarily driven by the level and volatility of oil prices. In addition, the proposed Federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. As a result of the suspension of production at the synthetic fuel-producing facilities and the level of oil prices, during the second quarter of 2006 Exelon recorded an impairment charge of $115 million ($69 million after tax) in operating and maintenance expense on Exelon’s Consolidated Statement of Operations to write off the net carrying value of the intangible asset related to Exelon’s investments in synthetic fuel-producing facilities. The net carrying value of the intangible assets associated with the synthetic fuel-producing facilities was $143 million at December 31, 2005. See Note 6 — Intangible Assets for additional information. Due to the reduction in oil prices during the third quarter of 2006, the operators resumed production at the synthetic fuel-producing facilities in September 2006 and are expected to produce at full capacity through the remainder of 2006.

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 its counterparties related to phased-out tax credits. At September 30, 2006, Exelon had receivables on its Consolidated Balance Sheet from the counterparties totaling $49 million associated with the portion of the payments previously made to the counterparties related to tax credits that are anticipated to be phased out in 2006. This receivable balance includes $7 million withheld from a counterparty as a result of the associated credit risk. As of September 30, 2006, Exelon has estimated the 2006 phase-out to be 44%, which has reduced Exelon’s earned after-tax credits of $96 million to $55 million for the nine months ended September 30, 2006. These credits may be further phased out during the remainder of 2006 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 its counterparties 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 counterparties has security interests in these derivatives. Including the related mark-to-market gains and losses on these derivatives, interests in synthetic fuel-producing facilities reduced Exelon’s net income by $13 million and increased Exelon’s net income by $28 million during the three months ended September 30, 2006 and 2005, respectively. Additionally, interests in synthetic fuel-producing facilities reduced net income by $55 million and increased net income by $73 million during the nine months ended September 30, 2006 and 2005, 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 or net losses from interests in synthetic fuel-producing facilities are 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 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 $108 million and $158 million at September 30, 2006 and December 31, 2005, 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.

1999 Sale of Fossil Generating Assets (Exelon 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 September 30, 2006 and December 31, 2005, 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. 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. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction ComEd entered into in connection with the sale is proper pursuant to applicable law. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. The IRS has recently indicated its position that the ComEd lease transaction is substantially similar to a leasing transaction 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. As a result of the IRS characterization of the lease transaction as a listed transaction, it is likely to vigorously challenge the transaction and will seek to obtain information not normally requested in audits. Exelon believes its position is correct and will aggressively defend that position upon audit and any subsequent appeals or litigation. However, a successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes currently payable. As of September 30, 2006, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $958 million. If the deferral were successfully challenged by the IRS, it could negatively affect Exelon’s results of operations by as much as $158 million (after tax) related to interest expense. Exelon’s management believes a reserve for interest has been appropriately recorded in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5); however, the ultimate outcome of this matter could result in unfavorable or favorable impacts to the results of operations, and such impacts could be material. Final resolution of this matter is not anticipated for several years.

Impact of Illinois Auction on State Income Taxes (Exelon and Generation)

In September 2006, the first reverse-auction competitive bidding process took place in Illinois. As such, Exelon assessed any impacts from the auction on its state income tax obligations and considered potential strategies and/or alternative interpretations that may be employed to mitigate these impacts. As a result, Exelon does not believe the auction will significantly affect the provision for state income taxes reported by Exelon on an annual basis. However, management’s estimates of future income tax rates are affected by various factors and actual income tax obligations may differ from management’s estimates. See Note 5 — Regulatory Issues for information regarding the reverse-auction competitive bidding process.

Pennsylvania Tax Law (Exelon and Generation)

On July 12, 2006, the Governor of Pennsylvania approved a law which increases the threshold for the usage of net operating losses for Pennsylvania corporate net income taxes. Under the new law, previously limited Pennsylvania net operating losses will be available to offset future taxable income, primarily at Generation. As a result, Exelon recorded a tax benefit to income taxes of approximately $10 million in the third quarter of 2006.


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

Nuclear Decommissioning Asset Retirement Obligations (ARO) (Exelon and Generation)

Both Generation and AmerGen Energy Company, LLC (AmerGen), a wholly owned subsidiary of Generation, have a legal obligation to decommission their nuclear power plants following the expiration of their respective operating licenses. Generation and AmerGen will pay for this obligation using trust funds that have been established for this purpose. Refer to Notes 13 and 16 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 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.

Generation updates its ARO on a periodic basis. 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 the following:


	•	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

	•	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 impact of the above items is effectively to push the estimated future nuclear decommissioning cash flows further into the future and, therefore, reduce the present value of the ARO. This decrease in the ARO resulted in the following corresponding impacts during the second quarter of 2006:


	•	A decrease in Generation’s asset retirement cost (ARC), which is included in property, plant and equipment in Exelon’s and Generation’s Consolidated Balance Sheets, of approximately $393 million;

	•	An increase in Generation’s intercompany payable to ComEd and PECO, which is included in non-current payable to affiliates in Generation’s Consolidated Balance Sheets, of approximately $62 million;

	•	An increase in ComEd’s and PECO’s intercompany receivables from Generation, which are included in non-current receivables from affiliates in ComEd’s and PECO’s Consolidated Balance Sheets, of approximately $36 million and $26 million, respectively, offset by equivalent increases in ComEd’s and PECO’s regulatory liabilities (these increases are reflected as increases in Exelon’s regulatory liabilities on Exelon’s Consolidated Balance Sheet); and

	•	The recognition of other operating income by Generation (and, therefore, also by Exelon) of $149 million (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, representing the reduction in the ARO in excess of the existing ARC balance for the AmerGen units.

The net decrease in the ARO for the former ComEd units, the former PECO units and the AmerGen units was approximately $219 million, $183 million and $202 million, respectively. As of September 30, 2006, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2,143 million, $899 million and $441 million, respectively.

The following table presents the activity of the ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from January 1, 2006 to September 30, 2006:


	Exelon and Generation

Nuclear decommissioning AROs at January 1, 2006	$	3,921
Net decrease resulting from updates to estimated future cash flows		(604	)
Accretion expense		176
Payments to decommission retired plants		(10	)

Nuclear decommissioning AROs at September 30, 2006	$	3,483

During the second quarter of 2005, Generation recorded a $281 million net decrease in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows, primarily due to a year-over-year decline in the cost escalation factors used to estimate future undiscounted costs, partially offset by an increase resulting from updated decommissioning cost studies received for two nuclear stations. Independent third-party appraisers provided both the updated escalation factors and the updated cost studies. There was no net impact to any of the Registrant’s Consolidated Statements of Operations and Comprehensive Income (Loss) resulting from the 2005 ARO update.

There were no updates to the ARO in the third quarter of 2006 or 2005.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

The trust funds that have been established to satisfy Generation’s nuclear decommissioning obligations were originally funded with amounts collected from customers. In certain circumstances, these trust funds will continue to be funded by future collections from customers.

At September 30, 2006 and December 31, 2005, both Exelon and Generation had nuclear decommissioning trust fund investments in the amounts of $6,072 million and $5,585 million, respectively.

At September 30, 2006, Exelon and Generation had gross unrealized gains of $1,019 million and gross unrealized losses of $31 million related to the nuclear decommissioning trust fund investments. At December 31, 2005, Exelon and Generation had gross unrealized gains of $734 million and gross unrealized losses of $47 million.

As a result of the sale of nuclear decommissioning trust fund investments, Exelon and Generation realized gains of $3 million and realized losses of $3 million for the three months ended September 30, 2006 and 2005, respectively, on nuclear decommissioning trust funds, of which realized losses of $1 million during the three months ended September 30, 2005 related to investments held in the AmerGen decommissioning trust funds. Additionally, Exelon and Generation realized losses of $8 million and realized gains of $52 million for the nine months ended September 30, 2006 and 2005, respectively, on nuclear decommissioning trust funds, of which realized losses of $2 million and realized gains of $38 million during the nine months ended September 30, 2006 and 2005, respectively, related to investments held in the AmerGen decommissioning trust funds. These gains were recognized primarily as a result of changes to the investment strategy associated with the mix of investments in the nuclear decommissioning trust funds in the first half of 2005. For the former ComEd and PECO units, these gains and losses have been reflected as a component of other income and, due to the impact of regulatory accounting, had no impact on the results of operations of Exelon and Generation.

Exelon and Generation evaluate decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During the three and nine months ended September 30, 2006, Exelon and Generation concluded that certain trust fund investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the value of the securities and consideration of Exelon’s and Generation’s ability and intent to hold the investments until the recovery of their cost basis. This determination resulted in impairment charges of $1 million and $11 million for the three and nine months ended September 30, 2006, respectively, which were recorded in other income and deductions associated with the trust funds for the decommissioning of the former ComEd plants. During the three and nine months ended September 30, 2005, both Exelon and Generation recorded impairment charges of $0 million and $2 million, respectively, which were recorded in other income and deductions associated with the trust funds for the decommissioning of the AmerGen plants. Also during the three and nine months ended September 30, 2005, both Exelon and Generation realized $0 and $12 million, respectively, of the previously unrealized losses associated with the trust investments for the decommissioning of the former ComEd plants. The realization of these losses associated with the former ComEd plants had no impact on Exelon’s and Generation’s results of operations or financial position since both realized and unrealized losses are already reflected in the fair value of the investments and in the fair value of the regulatory liability at ComEd.

Non-Nuclear AROs (Exelon, ComEd, PECO and Generation)

As of December 31, 2005, Exelon adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, Exelon is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated. The liabilities associated with conditional AROs will be adjusted periodically due to the passage of time, new laws and regulations, and revisions to either the timing or amount of the original estimates of undiscounted cash flows. See Note 14 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for a discussion of the accounting for non-nuclear asset retirement obligations.

The following table presents the activity of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2006 to September 30, 2006:


	Exelon			ComEd			PECO		Generation

Non-nuclear AROs at January 1, 2006	$	236		$	151		$	20	$	65
Accretion expense(a)		9			6			1		3
Settlements		(1	)		(1	)		—		—

Non-nuclear AROs at September 30, 2006	$	244		$	156		$	21	$	68


(a)		For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulations.


12.	Earnings Per Share and Shareholders’ Equity (Exelon)

Earnings per Share

Diluted earnings per share are 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 outstanding under Exelon’s stock option 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 on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	Three Months					Nine Months
	Ended					Ended
	September 30,					September 30,
	2006			2005		2006		2005

Income (loss) from continuing operations	$	(45)		$	724	$	997	$	1,747
Income (loss) from discontinued operations		1			1		3		13

Net income (loss)	$	(44	)	$	725	$	1,000	$	1,760

Average common shares outstanding — basic		671			670		670		669
Assumed exercise of stock options, performance share awards and restricted stock		—			7		6		7

Average common shares outstanding — diluted		671			677		676		676

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 4.0 million for the nine months ended September 30, 2006. There were no stock options excluded for the three or nine months ended September 30, 2005.

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 18 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for further information regarding Exelon’s share repurchase program. As of September 30, 2006, 10 million shares of common stock have been purchased under the share repurchase program for $483 million. During the nine months ended September 30, 2006, Exelon repurchased 0.9 million shares of common stock under the share repurchase program for $54 million.

During the nine months ended September 30, 2005, Exelon repurchased 0.2 million shares of common stock from a retired executive for $8 million.

These repurchased shares are held as treasury shares and are recorded at cost.


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

For information regarding capital commitments and nuclear decommissioning at December 31, 2005, see Notes 13 and 20 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K. All significant contingencies are disclosed below.

Energy Commitments

Under the PPA, as amended, between ComEd and Generation, Generation is supplying substantially all of ComEd’s load requirements through 2006. Subsequent to 2006, as a result of the first reverse-auction competitive bidding process, ComEd expects to procure substantially all of its supply under several supplier forward contracts with various suppliers. See Note 5 — Regulatory Issues for further information.


	•	Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $3.1 billion during the nine months ended September 30, 2006, reflecting increases of approximately $3.4 billion and $1.3 billion in 2007 and 2008 sales commitments, respectively, and other small increases in commitments in years beyond 2008, offset by the fulfillment of approximately $1.8 billion of 2006 commitments during the nine months ended September 30, 2006. The increases were primarily due to increased forward sales of energy to counterparties other than ComEd as a result of the pending expiration of the PPA with ComEd on December 31, 2006, as well as increased overall hedging activity in the normal course of business.

	•	Generation’s long term commitments for nuclear fuel as of September 30, 2006 increased by $340 million for 2009 and 2010, and $277 million for 2011 and beyond, as compared to December 31, 2005 due to contracts entered into in the normal course of business.

Commercial Commitments

Exelon’s, ComEd’s, PECO’s and Generation’s commercial commitments as of September 30, 2006, representing commitments potentially triggered by future events, did not change significantly from December 31, 2005, except for the following:


	•	Exelon’s letters of credit increased $60 million and guarantees (outside the scope of FIN 45) decreased $78 million primarily as a result of energy trading activities.

	•	ComEd’s letters of credit increased $16 million.

	•	PECO’s guarantees (outside the scope of FIN 45) decreased $9 million related to changes in surety bonds outstanding.

	•	Generation’s letters of credit increased $47 million and guarantees (outside the scope of FIN 45) decreased $35 million primarily as a result of energy trading activities.

Environmental Liabilities

Exelon, ComEd, PECO and Generation accrue amounts for environmental investigation and remediation costs that can be reasonably estimated, including amounts for manufactured gas plant (MGP) investigation and remediation. ComEd and PECO have identified 42 and 27 sites, respectively, where former MGP activities have or may have resulted in actual site contamination. Of these 42 sites identified by ComEd, the Illinois Environmental Protection Agency (Illinois EPA) has approved the clean up of eight sites, and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection has approved the cleanup of ten sites. Of the remaining sites identified by ComEd and PECO, 21 and 10 sites, respectively, are currently under some degree of active study and/or remediation.

ComEd and Nicor Gas Company, a subsidiary of Nicor Inc. (Nicor), are parties to an interim agreement under which they cooperate in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, may have responsibility. Under the interim agreement, costs are split evenly between ComEd and Nicor on an interim basis pending their final agreement on allocation of costs at each site, but either party may demand arbitration if the parties cannot agree on a final allocation of costs. For most of the sites, the interim agreement contemplates that neither party will pay less than 20%, nor more than 80% of the final costs for each site. ComEd’s accrual for these environmental liabilities is based on ComEd’s estimate of its 50% share of costs under the interim agreement with Nicor. On April 17, 2006, Nicor submitted a demand for arbitration of the cost allocation for 38 MGP sites. Through September 30, 2006, ComEd has incurred approximately $117 million associated with remediation of the sites in question. Although ComEd believes that the arbitration proceedings will not result in an allocation of costs materially different from ComEd’s current estimate of its aggregate remediation costs for MGP sites, the outcome of the arbitration proceedings is not certain and could result in a material increase or decrease of ComEd’s estimate of its share of the aggregate remediation costs.

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. Based on the final order received in ComEd’s Rate Case described in Note 5 — Regulatory Issues, beginning in 2007, ComEd will also recover its MGP remediation costs from customers for which it has set up a regulatory asset (see ComEd Rate Case below). See Note 14 — Supplemental Financial Information for further information regarding regulatory assets and

liabilities. As of September 30, 2006 and December 31, 2005, Exelon, ComEd, PECO and Generation had accrued the following amounts for environmental liabilities:


	Total
	Environmental
	Investigation and		Portion of Total Related
	Remediation		to MGP Investigation
September 30, 2006	Reserve		and Remediation

ComEd	$	59	$	50
PECO		45		43
Generation		21		—

Exelon	$	125	$	93


	Total
	Environmental
	Investigation and		Portion of Total Related
	Remediation		to MGP Investigation
December 31, 2005	Reserve		and Remediation(a)

ComEd	$	54	$	48
PECO		47		41
Generation		27		—

Exelon	$	128	$	89


(a)		Prior to the third quarter 2006, ComEd and PECO discounted their reserves for MGP investigation and remediation. The change from discounting to undiscounting was not deemed to be material for either ComEd or PECO.

During the first quarter of 2006, a court-approved settlement was completed between PECO and various potentially responsible parties associated with the remediation of a Superfund site commonly referred to as the Metal Bank or Cottman Avenue site. As a result of this settlement, PECO reversed a $4 million reserve it had previously recorded related to the site.

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 U.S. Environmental Protection Agency (EPA) issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will 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 and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, 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. There are many

factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to, obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, 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. AmerGen has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations, but believes that other compliance options under the final Phase II rule are viable and will be analyzed as part of the plant’s comprehensive demonstration study. If application of the Section 316(b) regulations requires the retrofitting of Oyster Creek’s cooling water intake structure or system, or extensive wetlands restoration, this could result in material costs of compliance and increased depreciation expense. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to renew the operating license.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG 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, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, 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 September 30, 2006, Generation has purchased three 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. The plaintiffs primarily seek (1) a court-supervised fund for medical monitoring for risks associated with alleged exposures to tritium and (2) compensation for diminished property values. Exelon filed a motion to dismiss the case, contending that the plaintiffs cannot meet the dose threshold required to maintain a public liability action under the Price-Anderson Act. This motion was denied. 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. Exelon has submitted its answer to the class action lawsuit; Exelon’s motions to dismiss the amended complaints in the other two lawsuits were denied in part on July 19, 2006. The court dismissed all claims premised on violations of Illinois environmental statutes. The Court has set a schedule for a class certification motion and discovery for all three suits. On September 29, 2006, amended complaints were filed in all three cases. Seven plaintiffs withdrew from the cases, and 18 additional plaintiffs were added. The substantive allegations are not materially different. Generation has tendered its defense of these lawsuits to its insurance carrier, American Nuclear Insurers (ANI), and ANI has agreed to defend the suits subject to a reservation of rights. Exelon, Generation and ComEd continue to believe that these lawsuits are without merit and intend to vigorously defend them. 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. None of the defendants have been served with the complaint.

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, and seeking injunctive relief, including (1) prohibiting Generation from using the line to discharge tritiated water until further court order and (2) requiring Generation to test the soil and groundwater contamination caused by the releases, to implement measures to prevent future releases and the migration of contaminants already in the groundwater, and to provide potable drinking water to area residents. The action also seeks the maximum civil penalties allowed by the statute and regulations, including penalties of $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 11, 2006, Exelon and Generation agreed with the Illinois Attorney General, the Illinois EPA and the State’s Attorney for Will County on the terms of a preliminary injunction order that enabled Generation to commence remediation of the tritiated groundwater at Braidwood. On May 24, 2006, the Circuit Court of Will County, Illinois entered an agreed order resulting in Generation commencing remediation efforts in June 2006 according to its February 2006 proposed remediation plan for tritium in groundwater off of plant property. Among other things, the May 24 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 Environmental Protection Agency safe drinking water standard. Any civil penalty will not be determined until the consent decree is finalized. Generation is unable to determine the amount of the penalty that will be sought. 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. Generation has been in continuing discussions related to this matter with the Illinois Attorney General and the State’s Attorney for Will County. Given the allegations in the lawsuit regarding the number of violations alleged and their duration, the civil penalty that could be imposed may be material to Exelon’s and Generation’s financial position, results of operations and cash flows.

On July 6, 2006, the Operations Committee of the Will County Forest Preserve District Board recommended that the Board file suit against Exelon. A small portion of the off-site contamination at Braidwood is on Forest Preserve property, which is adjacent to the affected pipeline. On July 13, 2006, the Board approved a resolution to file a lawsuit against Exelon if Exelon did not meet with the Board within 30 days to address its concerns. Since that time, on-going discussions have been held with representatives of the Forest Preserve District.

Generation has recorded a reserve related to the matters described above based on its current estimate of the costs of remediation, fines and potential related corrective measures.

On March 20, 2006, Generation announced that it would provide bottled water to Braidwood area residents, including the Village of Godley which was added at the request of the Illinois Attorney General, while drinking water wells are being tested for tritium. The cost of this bottled water program is not expected to be material and will be recorded in the period incurred. Generation has also pledged support to the Village of Godley for the installation of a new public drinking water system. The amount of this support cannot yet be determined because the level of financial participation from Federal, state or local governments is not yet known.

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 is considering referral to the Illinois Attorney General, the State’s Attorney for Ogle County, or the U.S. EPA for formal enforcement action and the imposition of penalties.

In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, in the first quarter of 2006 Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. The assessment covered pipes, pumps, valves, tanks and other pieces of equipment that carry or have carried tritiated water in and around the plants. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood, as discussed above, where past accidental tritiated water spills have been identified and state-approved cleanup work continues. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors. Generation management does not believe the costs of any required remediation or other additional work arising from the assessment would be material to Exelon’s or Generation’s financial position, results of operations or cash flows.

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 potentially responsible parties (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.

Air Quality Regulation

Pursuant to EPA regulations that will impose limits on certain future emissions by generation stations, the co-owners of the Keystone generating station formally approved on June 30, 2006 a capital plan to install environmental controls at the station for which Exelon’s share, based on its 20.99% ownership interest, would be approximately $150 million over the life of the control project.

Leases

The Registrants’ lease commitments as of September 30, 2006 did not change significantly from December 31, 2005. See Note 20 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for information regarding leases.

Litigation and Regulatory Matters

Exelon, PECO and Generation

Reverse-Employment Discrimination Claim. On April 4, 2005, one employee of PECO and four employees of Generation commenced suit in the United States District Court for the Eastern District of Pennsylvania, alleging that they were subjected to a practice of reverse age and race discrimination, which denied promotional opportunities to older white male employees, purportedly in violation of various Federal antidiscrimination statutes and the Pennsylvania Human Relations Act. The plaintiffs filed the action individually and on behalf of a putative class that included all white males currently or previously employed with any Exelon companies in the United States who were at least 40 years old on April 4, 2003 and who either applied for or were eligible to apply for supervisory positions in March 2003 and thereafter, continuing to the present day, and were not selected for those positions. Exelon, PECO and Generation filed an answer denying all liability. Additionally, since the initial claim was filed, the plaintiffs’ attorneys have identified two additional PECO employees and three additional Generation employees whom they are representing with similar claims, one of whom filed a separate reverse age and race discrimination lawsuit in the United States District Court for the Eastern District of Pennsylvania on July 28, 2006.

On June 12, 2006, the five named plaintiffs filed an amended complaint and a motion seeking certification of a class comprising all white male employees of Exelon, its subsidiaries, affiliates and operating units. On behalf of the class, the plaintiffs sought to enjoin certain of Exelon’s diversity efforts that they claim resulted in racially

discriminatory hiring, promotion, retention, termination and compensation practices, but no monetary damages. On June 29, 2006, Exelon, PECO and Generation filed an answer to the amended complaint again denying all liability.

On September 14, 2006, the court denied the plaintiffs’ request for class certification. In October 2006, PECO and Generation reached a tentative settlement with all parties to this matter and the parties are in the process of preparing formal settlement agreements. The amount of the settlement did not have a material impact on Exelon’s, PECO’s or Generation’s financial condition, results of operations or cash flows.

PJM Billing Dispute. In December 2004, Exelon filed with the FERC a complaint against PJM and PPL Electric alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’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 Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

On September 14, 2005, Exelon and PPL filed a proposed settlement of this matter with the FERC. See further discussion of this proposed settlement in Note 20 of Exelon’s consolidated financial statements included in Exelon’s 2005 Report on Form 10-K.

In an order issued March 21, 2006, FERC rejected the proposed settlement and set the matter for hearing, primarily because the proposed settlement would have required PJM market participants to bear $7.5 million of the $40.5 million settlement, plus interest. The order found that PPL should pay for energy received that was billed to other parties, but allows PPL and the market participants to question what portion of the settlement PJM might bear and what offsetting deductions might be made in reducing the payment. On March 30, 2006, Exelon and PPL filed with the FERC a second proposed settlement agreement, superceding the first, under which, if approved, Exelon would receive a total of $40.5 million, plus interest, over the next five years through credits provided by PJM, which would be funded through a surcharge imposed by PJM through its tariff solely on PPL Electric, with no amount being paid by other PJM participants. Following FERC approval of the settlement, this amount will be collected and paid by PJM to Exelon over a five-year period with interest on the unpaid principal accruing over the collection and payment period. It is anticipated that approximately 75% and 25% of the proposed settlement amount will be received by Generation and PECO, respectively.

Exelon expects this matter to be favorably resolved during 2006; however, pending FERC approval of the second proposed settlement agreement, as well as resolution of any third-party interventions, Exelon, Generation and PECO have not recorded any receivables associated with this matter.

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 Federal District Court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculated 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. On September 5, 2006, the Plan moved to dismiss the complaint. That motion is pending.

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 the 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 on behalf of the Savings Plan and participants, including alleged investment losses. The defendants’ response is due to be filed on November 7, 2006.

ComEd

ComEd Rate Case. As reported in Note 13 — Commitments and Contingencies in its June 30, 2006 Form 10-Q, ComEd requested recovery of amounts as part of its current Rate Case, which have previously been recorded as expense. Specifically, ComEd requested the following (all amounts pre-tax):


	•	recovery of approximately $87 million related to losses on extinguishment of long-term debt as part of ComEd’s 2004 Accelerated Liability Management Plan;

	•	recovery of $40 million of previously incurred MGP costs;

	•	recovery of $158 million of previously incurred severance costs; and

	•	recovery of $5 million of expenses previously incurred in the Procurement Case.

As discussed in Note 5 — Regulatory Issues, ComEd received a final order from the ICC on July 26, 2006, which approved recovery of certain of these costs. Exelon and ComEd had anticipated recording a one-time benefit to reverse these prior charges and Exelon and ComEd did recognize a one-time benefit during the third quarter of 2006 of approximately $130 million (pre-tax) related to the losses on the extinguishment of long-term debt, MGP costs and Procurement Case costs where the recovery mechanism was specifically identified by the ICC final order. While ComEd believes the intent of the Rate Order is to allow ComEd recovery of the previously incurred severance costs through its administrative and general (A&G) expenses, ComEd has requested clarification from the ICC on rehearing related to the amount of A&G expenses it should be allowed to recover. The ICC has agreed to rehear ComEd’s A&G costs, as well as several other items referred to in Note 5 — Regulatory Issues. ComEd has not yet recorded the anticipated one-time benefit for the previously incurred severance costs pending the resolution of the rehearing process.

Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation, as amended, required a 15% residential base rate reduction effective August 1, 1998 and an additional 5% residential base rate reduction effective October 1, 2001. In addition, a base rate freeze, reflecting the residential base rate reduction, is in effect through January 1, 2007. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is 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 include ComEd’s net income calculated in accordance with GAAP and reflect the amortization of regulatory assets. Under Illinois statute, any impairment of goodwill would have no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. ComEd will complete its next assessment of the earnings sharing provision during the first quarter of 2007. ComEd has not triggered the earnings sharing provision through 2005.

Generation

Asbestos 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. See further discussion in Note 17 of Generation’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K. During the second quarter of 2006, Generation performed a periodic update to this reserve, which did not result in a material adjustment.

At September 30, 2006 and December 31, 2005, Generation had reserved approximately $48 million and $50 million, respectively, for asbestos-related bodily injury claims. As of September 30, 2006, approximately $9 million of this amount relates to 120 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 plans to obtain annual 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.

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 shut down. The total shutdown period resulted in lost sales from the plant. Generation and PSEG have filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund (Fund). As this matter represents a contingent gain, Generation has recorded no income resulting from this claim. Although no assurances can be given, Generation’s management believes it is reasonably possible that damages and losses could be recovered and that Generation’s portion of the estimated proceeds arising from the claim could be approximately $25 million. Recently the Fund informed Generation that it will not address this claim until 2007. Based upon the Fund’s position, timing of the recovery cannot be estimated at this time.

PECO and Generation

Real Estate Tax Appeals. PECO and Generation have been challenging real estate taxes assessed on certain nuclear plants. PECO is involved in litigation in which it is contesting 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). Generation is involved in real estate tax appeals for 2000 through 2004 regarding the valuation of its Peach Bottom plant and is in the process of evaluating appraisals and preparing for negotiations. Generation was also previously involved in an appeal regarding the valuation of its LaSalle Nuclear plant. On March 9, 2006, the Illinois Circuit Court for LaSalle County approved the property tax settlement agreement agreed upon in late 2005 between all

taxing bodies with jurisdiction over the plant and Generation. The settlement agreement resolved all pending litigation concerning assessments on the property and sets the assessments for the tax years 2005 through 2008. PECO and Generation believe their reserve balances for exposures associated with real estate taxes as of September 30, 2006 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable impacts to the consolidated financial statements of Exelon, PECO and Generation and such impacts could be material.

Exelon, ComEd, PECO and Generation

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

Income Taxes

Refund Claims. 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 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 Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination” (EITF 93-7). Exelon cannot predict the timing of the final resolution of these refund claims. During the second quarter of 2006, the IRS indicated to PECO that it agreed with a substantial portion of one such refund claim. This refund claim will have to be approved by the Joint Committee on Taxation (Joint Committee). Based on the IRS’ indication of its agreement with a portion of the refund claim, PECO recorded an estimated tax consulting contingent fee of $3 million during the second quarter of 2006.

In the third quarter of 2006, the Joint Committee completed its review and granted approval for one of PECO’s income tax refund claims. As a result, the investment tax credit refund and associated interest of $19 million (after-tax) have been recorded as a credit in Exelon’s and PECO’s Consolidated Statements of Operations in the third quarter of 2006. Since a majority of the investment tax credits claimed related to PECO’s formerly owned generation property, a significant portion of the related unamortized investment tax credit and the tax impacts thereon were recorded at Generation. Therefore, Exelon and Generation recorded unamortized investment tax credits and related tax impacts of $10 million (after-tax) as a charge to their Consolidated Statements of Operations. The unamortized investment tax credit recorded at Exelon, PECO and Generation will be amortized over the remaining depreciable book lives of the transmission, distribution and generation property using the deferral method pursuant to APB No. 2, “Accounting for the ‘Investment Credit’” and APB No. 4, “Accounting for the ‘Investment Credit’.” In addition, as a result of the approval of the refund claim, Exelon and PECO recorded a consulting expense of $3 million (after-tax) in the third quarter of 2006. The net after-tax result of this settlement and consulting fees was $6 million, $16 million and $(10) million for Exelon, PECO and Generation, respectively.

Other Refund Claims. ComEd and PECO have filed several tax refund claims with Federal and state taxing authorities. ComEd and PECO are unable to estimate the ultimate outcome of these refund claims and will account for any amount received in the period the matters are settled with the Federal and state taxing authorities. To the

extent ComEd is successful on any of its refund claims a portion of the tax and interest benefit may be recorded to goodwill under the provisions of EITF 93-7.

Other. 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. See Note 10 — Income Taxes for further information.


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

Supplemental Income Statement Information

The following tables provide additional information regarding the components of other, net within the Consolidated Statements of Operations and Comprehensive Income (Loss) of Exelon, ComEd, PECO and Generation for the three and nine months ended September 30, 2006 and 2005:


	Three Months
	Ended						Nine Months Ended
	September 30,						September 30,
Exelon	2006			2005			2006			2005

Investment income	$	1		$	2		$	6		$	7
Gain on disposition of assets and investments, net		1			1			(1	)		9
Loss on settlement of cash-flow interest-rate swaps(a)		—			(15	)		—			(15	)
Decommissioning-related activities:
Decommissioning trust fund income(b)		43			27			109			106
Decommissioning trust fund income — AmerGen(b)		9			9			28			68
Other-than-temporary impairment of decommissioning trust funds		(1	)		—			(11	)		(12	)
Other-than-temporary impairment of decommissioning trust funds — AmerGen		—			—			—			(2	)
Regulatory offset to non-operating decommissioning-related activities(c)		(42	)		(27	)		(99	)		(94	)
Net direct financing lease income		2			5			13			16
Allowance for funds used during construction(AFUDC), equity		1			1			1			4
Unrealized income tax credits(d)		(4	)		—			49			—
Regulatory recovery of prior loss on extinguishment of long-term debt(e)		87			—			87			—
Interest income related to investment tax credit refund(f)		10			—			10			—
Other		7			8			13			21

Other, net	$	114		$	11		$	205		$	108


(a)		See Note 17 — Derivative Financial Instruments for further discussion of the loss on settlement of cash-flow interest-rate swaps.

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

(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 for certain nuclear units. See Notes 13 and 16 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for more information regarding the regulatory accounting applied for certain nuclear units.

(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.

(e) See Note 5 — Regulatory Issues for further discussion of the loss on extinguishment of long-term debt. Recovery of these costs was granted in the July 26, 2006 ICC rate order.

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


	Three Months					Nine Months
	Ended					Ended
	September 30,					September 30,
ComEd	2006		2005			2006			2005

Investment income	$	—	$	1		$	1		$	3
Gain (loss) on disposition of assets and investments, net		—		—			(2	)		4
AFUDC, equity		1		1			1			3
Loss on settlement of cash-flow interest-rate swaps(a)		—		(15	)		—			(15)
Regulatory recovery of prior loss on extinguishment of long-term debt(b)		87		—			87			—
Other		1		3			3			5

Other, net	$	89	$	(10)		$	90		$	—


(a)		See Note 17 — Derivative Financial Instruments for further discussion of the loss on settlement of cash-flow interest-rate swaps.

(b)		See Note 5 — Regulatory Issues for further discussion of the loss on extinguishment of long-term debt. Recovery of these costs was granted in the July 26, 2006 ICC rate order.


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
PECO	2006		2005		2006		2005

Interest income related to investment tax credit refund(a)	$	10	$	—	$	10	$	—
Investment income		1		1		5	$	4
Gain (loss) on disposition of assets and investments, net		—		1		—		5
Other		—		—		1		1

Other, net	$	11	$	2	$	16	$	10


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

Three Months
Nine Months

Ended
Ended

September 30, September 30,

Generation
2006 2005 2006 2005

Decommissioning-related activities:

Decommissioning trust fund income(a)
$ 43 $ 27 $ 109 $ 106

Decommissioning trust fund income — AmerGen(a)
9 9 28 68

Other-than-temporary impairment of decommissioning trust funds
(1 ) — (11 ) (12 )

Other-than-temporary impairment of decommissioning trust funds — AmerGen
— — — (2 )

Contractual offset to non-operating decommissioning-related activities(b)
(42) (27) (99 ) (94 )

Other
3 4 4 16

Other, net
$ 12 $ 13 $ 31 $ 82


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

(b)		Includes the elimination of non-operating decommissioning-related activity for those units that are subject to contractual accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Notes 13 and 16 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for more information regarding the regulatory accounting applied for certain nuclear units.

Supplemental Cash Flow Information

The following tables provide additional information regarding the components of impairment charges, other non-cash operating activities and other assets and liabilities within the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005:


	Nine Months
	Ended
	September 30,
Exelon	2006			2005

Impairment charges:
Impairment of goodwill	$	776		$	—
Impairment of long-lived assets		115			—
Other		2			—

Total impairment charges	$	893		$	—

Other non-cash operating activities:
Pension and non-pension postretirement benefits expense	$	140		$	123
Equity in losses of unconsolidated affiliates		74			107
Provision for uncollectible accounts		73			48
Net realized (gains) losses on nuclear decommissioning trust funds		8			(52	)
Gains on sales of investments and wholly owned subsidiaries		(1	)		(19	)
Other decommissioning-related activities		(150	)		18
Write-off of Merger-related capitalized costs(a)		46			—
Other		65			39

Total other non-cash operating activities	$	255		$	264

Changes in other assets and liabilities:
Other current assets	$	(79	)	$	(68	)
Other noncurrent assets and liabilities		(302	)		(99	)

Total changes in other assets and liabilities	$	(381	)	$	(167	)


(a)		Represents the Merger-related capitalized costs paid prior to 2006.

Nine Months

Ended

September 30,

ComEd
2006 2005

Other non-cash operating activities:

Provision for uncollectible accounts
$ 22 $ 21

Equity in losses of unconsolidated affiliates
8 11

Pension and non-pension postretirement benefits expense
30 26

Other
37 46

Total other non-cash operating activities
$ 97 $ 104

Changes in other assets and liabilities:

Other current assets
$ (11 ) $ (12 )

Other noncurrent assets and liabilities
(132 ) (16 )

Total changes in other assets and liabilities
$ (143 ) $ (28 )


	Nine Months
	Ended
	September 30,
PECO	2006			2005

Other non-cash operating activities:
Provision for uncollectible accounts	$	49		$	26
Equity in losses of unconsolidated affiliates		7			12
Pension and non-pension postretirement benefits expense		13			13
Other		8			—

Total other non-cash operating activities	$	77		$	51

Changes in other assets and liabilities:
Deferred/over-recovered energy costs	$	51		$	8
Other current assets		(12	)		(33	)
Other noncurrent assets and liabilities		3			28

Total changes in other assets and liabilities	$	42		$	3

Nine Months

Ended

September 30,

Generation
2006 2005

Other non-cash operating activities:

Provision for uncollectible accounts
$ 2 $ —

Equity in losses of unconsolidated affiliates
9 (2 )

Gains on sales of investments and wholly owned subsidiaries
(2 ) (21 )

Net realized (gains) losses on nuclear decommissioning trust funds
8 (52 )

Pension and non-pension postretirement benefits expense
79 68

Other decommissioning-related activities
(150 ) 18

Other
23 (28 )

Total other non-cash operating activities
$ (31 ) $ (17 )

Changes in other assets and liabilities:

Other current assets(a)
$ (98 ) $ (33 )

Other noncurrent assets and liabilities(b)
(157 ) (64 )

Total changes in other assets and liabilities
$ (255) $ (97)


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

(b)		Relates primarily to the purchase of long-term fuel options.

Supplemental Balance Sheet Information

The following tables provide additional information regarding the regulatory assets and liabilities of Exelon, ComEd and PECO:


	September 30,			December 31,
Exelon and ComEd	2006			2005

Regulatory assets (liabilities):
Nuclear decommissioning	$	(1,620	)	$	(1,435	)
Removal costs		(1,046	)		(1,015	)
Debt costs(a)(b)		183			107
Conditional asset retirement obligations		95			91
MGP remediation costs(b)		47			—
Recoverable transition costs		12			43
Deferred income taxes		9			8
Rate case costs(b)		7			—
Procurement case costs(b)		5			—
Other		26			31

Total net regulatory liabilities	$	(2,282)		$	(2,170)


(a)		Includes reacquired debt costs, interest rate swap settlements and early debt retirement costs. Recovery of early debt retirement costs was granted in the July 26, 2006 ICC rate order. See Note 5 — Regulatory Issues.

(b)		Recovery of these items was granted in the July 26, 2006 ICC rate order. See Note 5 — Regulatory Issues.


	September 30,			December 31,
Exelon and PECO	2006			2005

Regulatory assets (liabilities):
Competitive transition charges	$	3,109		$	3,532
Deferred income taxes		789			781
Non-pension postretirement benefits		41			45
Reacquired debt costs		32			36
MGP remediation costs		25			26
Conditional asset retirement obligations		14			13
U.S. Department of Energy facility decommissioning		8			13
Nuclear decommissioning		(112	)		(68	)
Other		11			8

Long-term regulatory assets		3,917			4,386
Deferred (over-recovered) energy costs — current asset (liability)		(12	)		39

Total net regulatory assets	$	3,905		$	4,425

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of September 30, 2006 and December 31, 2005:


September 30, 2006	Exelon			ComEd		PECO		Generation

Property, plant and equipment:
Accumulated depreciation	$	7,201	(a)	$	1,391	$	2,207	$	3,450	(a)
Accounts receivable:
Allowance for uncollectible accounts		90			19		51		17


(a)		Includes accumulated amortization of nuclear fuel in the reactor cores of $1,166 million.


December 31, 2005	Exelon			ComEd		PECO		Generation

Property, plant and equipment:
Accumulated depreciation	$	7,872	(a)	$	1,253	$	2,172	$	4,315	(a)
Accounts receivable:
Allowance for uncollectible accounts		77			20		39		15


(a)		Includes accumulated amortization of nuclear fuel in the reactor cores of $2,103 million.

The following table provides information regarding counterparty margin deposit accounts and option premiums as of September 30, 2006 and December 31, 2005:


	September 30,		December 31,
Exelon and Generation	2006		2005

Other current assets:
Counterparty collateral asset	$	49	$	285
Option premiums		199		126
Other current liabilities:
Counterparty collateral liability		260		101


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

Exelon has three reportable segments: ComEd, PECO and Generation. Exelon evaluates the performance of its segments based on net income. As a result of developments during the fourth quarter of 2005, Exelon concluded that it could no longer aggregate ComEd and PECO as a single reportable segment. These developments included the approaching end of the regulatory transition period and rate freeze in Illinois, the opposition to rate increases expressed by the Attorney General of the State of Illinois, changes in ComEd’s Board of Directors and the selection of executive officers of ComEd with no responsibilities outside of ComEd. As a result, ComEd and PECO are no longer reported as a combined Energy Delivery reportable segment. For more information regarding ComEd’s regulatory issues, see Note 5 — Regulatory Issues. Prior period presentation has been adjusted for comparative purposes.

ComEd, PECO and Generation each operate in a single business segment; as such, no separate segment information is provided for these registrants.

Three Months Ended September 30, 2006 and 2005

Exelon’s segment information for the three months ended September 30, 2006 and 2005 is as follows:


	ComEd			PECO		Generation		Other(a)			Eliminations			Consolidated

Total revenues(b):
2006	$	1,840		$	1,379	$	2,635	$	205		$	(1,658	)	$	4,401
2005		1,948			1,322		2,711		190			(1,698	)		4,473
Intersegment revenues:
2006	$	2		$	2	$	1,449	$	205		$	(1,658	)	$	—
2005		2			2		1,504		190			(1,698	)		—
Income (loss) from continuing operations before income taxes:
2006	$	(329	)	$	180	$	637	$	(167	)	$	—		$	321
2005		379			248		553		(112	)		—			1,068
Income taxes:
2006	$	177		$	46	$	244	$	(101	)	$	—		$	366
2005		155			82		219		(112	)		—			344
Income (loss) from continuing operations:
2006	$	(506	)	$	134	$	393	$	(66	)	$	—		$	(45	)
2005		224			166		334		—			—			724
Income (loss) from discontinued operations:
2006	$	—		$	—	$	1	$	—		$	—		$	1
2005		—			—		1		—			—			1
Net income (loss):
2006	$	(506	)	$	134	$	394	$	(66	)	$	—		$	(44	)
2005		224			166		335		—			—			725


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

(b)		For the three months ended September 30, 2006 and 2005, utility taxes of $69 million and $71 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2006 and 2005, utility taxes of $72 million and $72 million, respectively, are included in revenues and expenses for PECO.

Exelon’s segment information for the nine months ended September 30, 2006 and 2005 is as follows:


	ComEd			PECO		Generation		Other(a)			Eliminations			Consolidated

Total revenues (b):
2006	$	4,720		$	3,933	$	7,069	$	615		$	(4,377	)	$	11,960
2005		4,822			3,661		6,836		533			(4,333	)		11,519
Intersegment revenues:
2006	$	6		$	6	$	3,751	$	614		$	(4,377	)	$	—
2005		6			6		3,789		532			(4,333	)		—
Income (loss) from continuing operations before income taxes:
2006	$	(25	)	$	460	$	1,855	$	(364	)	$	—		$	1,926
2005		676			605		1,530		(285	)		—			2,526
Income taxes:
2006	$	300		$	140	$	696	$	(207	)	$	—		$	929
2005		273			200		595		(289	)		—			779
Income (loss) from continuing operations:
2006	$	(325	)	$	320	$	1,159	$	(157	)	$	—		$	997
2005		403			405		935		4			—			1,747
Income (loss) from discontinued operations:
2006	$	—		$	—	$	4	$	(1	)	$	—		$	3
2005		—			—		16		(3	)		—			13
Net income (loss):
2006	$	(325	)	$	320	$	1,163	$	(158	)	$	—		$	1,000
2005		403			405		951		1			—			1,760
Total assets:
September 30, 2006	$	17,007		$	9,565	$	17,824	$	13,307		$	(16,055	)	$	41,648
December 31, 2005		17,211			10,018		17,724		13,079			(15,583	)		42,449


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

(b)		For the nine months ended September 30, 2006 and 2005, utility taxes of $188 million and $192 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2006 and 2005, utility taxes of $187 million and $177 million, respectively, are included in revenues and expenses for PECO.

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

Exelon and ComEd

The financial statements of Exelon and ComEd include related-party balances and transactions with unconsolidated affiliates as presented in the tables below:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005

Operating revenues from affiliates
ComEd Transitional Funding Trust	$	1	$	1	$	2	$	2
Interest expense to affiliates
ComEd Transitional Funding Trust		11		15		36		51
ComEd Financing II		4		3		10		10
ComEd Financing III		3		4		10		10
Equity in losses of unconsolidated affiliates
ComEd Funding LLC		2		3		8		11


	September 30,		December 31,
	2006		2005

Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	18	$	14
Investment in affiliates ComEd Funding LLC		6		18
ComEd Financing II		10		10
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust		13		12
Payables to affiliates (current)
ComEd Transitional Funding Trust		—		1
ComEd Financing II		3		6
ComEd Financing III		—		4
Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust		726		987
ComEd Financing II		155		155
ComEd Financing III		206		206

In addition to the transactions described above, ComEd’s financial statements include related-party balances and transactions as presented in the tables below:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005

Operating revenues from affiliates
Generation(a)	$	2	$	2	$	6	$	6
Purchased power from affiliate
PPA with Generation(b)		907		991		2,363		2,514
Operations and maintenance from affiliates
BSC(c)		55		50		160		139
Interest income from affiliates
Exelon intercompany money pool(d)		—		—		—		3
Capitalized costs
BSC(c)		20		16		56		46
Cash dividends paid to parent		—		107		—		352


	September 30,		December 31,
	2006		2005

Receivables from affiliates (current)
Exelon(e)	$	—	$	23
Receivables from affiliates (noncurrent)
Generation(f)		1,620		1,435
Payables to affiliates (current)
Exelon(e)		26		—
Generation decommissioning(g)		11		11
Generation(a),(b)		175		242
BSC(c)		19		14
Borrowings from Exelon intercompany money pool(d)		—		140


(a)		ComEd provides retail electric and ancillary services to Generation.

(b)		ComEd has entered into a full-requirements PPA, as amended, with Generation. See Note 17 of ComEd’s Notes to Consolidated Financial Statements within ComEd’s 2005 Annual Report on Form 10-K for more information regarding the PPA.

(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 participated in Exelon’s intercompany money pool, whereby ComEd earned interest on its contributions to the money pool and paid interest on its borrowings from the money pool at a market rate of interest. As of January 10, 2006, ComEd suspended participation in the money pool and on February 22, 2006, entered into a $1 billion senior secured three year revolving credit agreement among a group of lenders. See Note 7 — Debt and Credit Agreements for additional information.

(e) ComEd has a payable to Exelon under the Tax Sharing Agreement which is partially offset by a receivable from Exelon for the allocation of tax benefits. The December 31, 2005 receivable from Exelon for the allocation of tax benefits was settled in 2006. See Note 10 — Income Taxes for additional information.

(f) 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. See Note 11 of ComEd’s Notes to Consolidated Financial Statements within ComEd’s 2005 Annual Report on Form 10-K for additional information.

(g) ComEd has a short-term payable to Generation, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation.

Exelon and PECO

The financial statements of Exelon and PECO include related-party balances and transactions with unconsolidated financing subsidiaries as presented in the tables below:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005

Operating revenues from affiliates
PETT(a)	$	2	$	2	$	6	$	7
Interest expense to affiliates, net
PETT		44		52		138		162
PECO Trust III		2		2		5		5
PECO Trust IV		1		1		4		4
Equity in losses of unconsolidated affiliates
PETT		2		4		7		12


	September 30,		December 31,
	2006		2005

Investment in affiliates
PETT	$	57	$	63
PECO Energy Capital Corp.		4		4
PECO Trust IV		6		6
Payables to affiliates (current)
PECO Trust III		2		1
PECO Trust IV		2		—
Long-term debt to PETT and other financing trusts (including due within one year)
PETT		2,545		2,975
PECO Trust III		81		81
PECO Trust IV		103		103


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

In addition to the transactions described above, PECO’s financial statements include related-party balances and transactions as presented in the tables below:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005

Operating revenues from affiliates
Generation(a)	$	2	$	2	$	6	$	6
Purchased power from affiliate
Generation(b)		542		513		1,387		1,273
Fuel
Generation(c)		—		—		—		1
Operations and maintenance from affiliates
BSC(d)		31		28		93		80
Other		—		—		1		1
Interest expense to affiliates, net
Other				—		1		(1	)
Capitalized costs
BSC(d)		12		14		41		26
Cash dividends paid to parent		117		116		368		347


	September 30,		December 31,
	2006		2005

Receivable from affiliate (current)
Exelon(e)	$	26	$	13
Contributions to Exelon intercompany money pool(f)		—		8
Receivable from affiliate (noncurrent)
Generation decommissioning(g)		112		68
Payables to affiliates (current)
Generation(b)		142		151
BSC(d)		29		26
Shareholders’ equity — receivable from parent(h)		1,126		1,232


(a)		PECO provides energy to Generation for Generation’s own use.

(b)		PECO has entered into a full-requirements PPA with Generation. See Note 15 of PECO’s Notes to Consolidated Financial Statements within PECO’s 2005 Annual Report on Form 10-K for more information regarding the PPA.

(c)		Effective April 1, 2004, PECO entered into a one-year gas procurement agreement with Generation.

(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)		Includes a receivable from Exelon for the allocation of tax benefits. The December 31, 2005 receivable from Exelon for the allocation of tax benefits was settled in 2006. See Note 10 — Income Taxes for additional information.

(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 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. See Note 9 of PECO’s Notes to Consolidated Financial Statements within PECO’s 2005 Annual Report on Form 10-K for additional information.

(h) 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 2006 through 2010.

Generation

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


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2006		2005		2006		2005

Operating revenues from affiliates ComEd(a)	$	907	$	991	$	2,363	$	2,514
PECO(a)		542		513		1,387		1,274
BSC		—		—		1		1
Fuel
PECO(b)		—		—		1		1
Operations and maintenance from affiliates
ComEd(b)		2		2		6		6
PECO(b)		2		2		5		5
BSC(c)		69		64		214		190
Interest expense to affiliate
Exelon intercompany money pool(d)		2		—		3		2
Cash distribution paid to member		122		430		444		749
Cash contribution received from member		5		—		5		843

September 30,
December 31,

2006 2005

Receivables from affiliates (current)

ComEd(a)
$ 175 $ 242

ComEd decommissioning(e)
11 11

PECO(a)
142 151

BSC(c)
— 7

Payables to affiliates (current)

Exelon(f)
12 4

Ventures(h)
15 —

BSC(c)
33 —

Borrowings from Exelon intercompany money pool(d)
6 92

Payables to affiliates (noncurrent)

ComEd decommissioning(g)
1,620 1,435

PECO decommissioning(g)
112 68


(a)		Generation has entered into PPAs with ComEd and PECO, as amended, to provide the full energy requirements of ComEd and PECO. See Note 17 of Generation’s Notes to Consolidated Financial Statements within Generation’s 2005 Annual Report on Form 10-K for additional information regarding the PPAs.

(b)		Generation purchases retail electric and ancillary services from ComEd and buys power from PECO for Generation’s own use. See Note 17 of Generation’s Notes to Consolidated Financial Statements within Generation’s 2005 Annual Report on Form 10-K for additional information regarding the PPAs.

(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 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.

(e)		Generation has a short-term receivable from ComEd, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation.

(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 tax benefits. The December 31, 2005 receivable from Exelon for the allocation of tax benefits was settled in 2006. See Note 10 — Income Taxes for additional information.

(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 13 of Generation’s Notes to Consolidated Financial Statements within Generation’s 2005 Annual Report on Form 10-K for additional information.

(h)		Includes a payable from Exelon Ventures Company, LLC (Ventures) for the allocation of state tax benefits.


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

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

The fair values of Exelon’s, ComEd’s, PECO’s and Generation’s interest-rate swaps are determined using quoted exchange prices, external dealer prices and available market pricing curves. At September 30, 2006, the Registrants did not have any interest-rate related fair-value or cash-flow hedges outstanding. At December 31, 2005,

Exelon had $240 million of notional amounts of interest-rate swaps outstanding, which were held by ComEd and were settled on January 17, 2006 for a cash payment of approximately $1 million.

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 September 30, 2006, the Registrants did not have any 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 transaction 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 months and nine months ended September 30, 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 accumulated other comprehensive income (OCI). Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. At September 30, 2006 and 2005, the Registrants did not have any notional amounts of interest-rate related cash-flow hedges outstanding.

During the three months ended September 30, 2005, as a result of a forecasted transaction no longer being probable, Exelon and ComEd settled interest-rate swaps in the aggregate notional amount of $325 million and recorded net pre-tax losses of $15 million which were included in other, net within Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income (Loss). During the nine months ended September 30, 2005, Exelon settled interest-rate swaps in aggregate notional amounts of $1.8 billion and recorded net pre-tax losses of $54 million, of which $15 million was included in other, net within Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income (Loss). Exelon is recording the remaining $39 million as additional interest expense over the remaining life of the debt.

Energy-Related Derivatives (Exelon, ComEd and Generation)

Generation utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates. 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.

Exelon’s, ComEd’s and Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts may qualify for the normal purchases and normal sales exception to SFAS No. 133. Those that do not meet the normal purchase 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 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 20 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K.

At September 30, 2006 Exelon, ComEd and Generation had net asset (liabilities) of $233 million, $(9) million and $230 million, respectively, on their Consolidated Balance Sheets for the fair value of energy derivatives, which included the energy derivatives at Exelon and Generation discussed below. The following table provides a summary of the fair value balances recorded by Exelon, ComEd and Generation as of September 30, 2006:


																									Exelon
	Generation												ComEd												Energy-
	Cash-Flow			Other			Proprietary						Cash-Flow			Other									Related
Derivatives	Hedges			Derivatives			Trading			Subtotal			Hedge			Derivatives			Subtotal			Other(a)			Derivatives

Current assets	$	240		$	407		$	150		$	797		$	—		$	—		$	—		$	12		$	809
Noncurrent assets		156			131			48			335			—			—			—			35			370

Total mark-to-market energy contract assets	$	396		$	538		$	198		$	1,132		$	—		$	—		$	—		$	47		$	1,179

Current liabilities	$	(223	)	$	(359	)	$	(141	)	$	(723	)	$	(4	)	$	(4	)	$	(8	)	$	(15	)	$	(746	)
Noncurrent liabilities		(56	)		(78	)		(45	)		(179	)		—			(1	)		(1	)		(20	)		(200	)

Total mark-to-market energy contract liabilities	$	(279	)	$	(437	)	$	(186	)	$	(902	)	$	(4	)	$	(5	)	$	(9	)	$	(35	)	$	(946	)

Total mark-to-market energy contract net assets (liabilities)	$	117		$	101		$	12		$	230		$	(4	)	$	(5	)	$	(9	)	$	12		$	233


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

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 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 (ComEd and Generation). The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on ComEd and Generation’s Consolidated Balance Sheets as of September 30, 2006. The data in the table is indicative of the magnitude of SFAS No. 133 hedges ComEd and Generation 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 ComEd and Generation’s derivatives. The tables also include the activity of accumulated OCI related to cash-flow hedges for the three and nine months ended September 30, 2006 and 2005, providing information about the changes in the fair value of hedges and the reclassification from OCI into earnings.

Total Cash-Flow

Hedge OCI Activity,

Net of Income Tax

Three Months Ended September 30, 2006
ComEd Generation

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

Changes in fair value
(2 ) 114

Reclassifications from OCI to net income
— 40

Accumulated OCI derivative gain (loss) at September 30, 2006
$ (2 ) $ 70


	Total Cash-Flow
	Hedge OCI Activity,
	Net of Income Tax
Nine Months Ended September 30, 2006	ComEd			Generation

Accumulated OCI derivative loss at December 31, 2005	$	—		$	(314	)
Changes in fair value		(2	)		277
Reclassifications from OCI to net income		—			107

Accumulated OCI derivative gain (loss) at September 30, 2006	$	(2	)	$	70


	Total Cash-Flow
	Hedge OCI Activity,
	Net of Income Tax
Three Months Ended September 30, 2005	ComEd		Generation

Accumulated OCI derivative loss at June 30, 2005	$	—	$	(224	)
Changes in fair value		—		(273	)
Reclassifications from OCI to net income		—		92

Accumulated OCI derivative loss at September 30, 2005	$	—	$	(405	)


	Total Cash-Flow
	Hedge OCI Activity,
	Net of Income Tax
Nine Months Ended September 30, 2005	ComEd		Generation

Accumulated OCI derivative loss at December 31, 2004	$	—	$	(137	)
Changes in fair value		—		(477	)
Reclassifications from OCI to net income		—		209

Accumulated OCI derivative loss at September 30, 2005	$	—	$	(405	)

At September 30, 2006, ComEd and Generation had net unrealized pre-tax gains (losses) on cash-flow hedges of $(4) million and $117 million in accumulated OCI, respectively. Based on market prices at September 30, 2006, approximately $(4) million and $16 million of these deferred net pre-tax unrealized gains (losses) on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months by ComEd and Generation, respectively. 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. ComEd’s cash flow hedge expires on May 31, 2007, while the majority of Generation’s cash-flow hedges are expected to settle within the next three years.

Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $66 million pre-tax gain and a $178 million pre-tax gain for the three and nine months ended September 30, 2006, respectively, and a $151 million pre-tax loss and a $340 million pre-tax loss for the three and nine months ended September 30, 2005, respectively.

Other Derivatives (Exelon, ComEd and Generation). Exelon, ComEd and Generation 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 nine months ended September 30, 2006 and 2005, Exelon, ComEd and Generation 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 mark-to-market activity of certain non-trading purchase power and sale contracts pursuant to SFAS No. 133. Generation’s, ComEd’s and Exelon’s other mark-to-market activity on non-trading purchase power and sale contracts are reported in fuel and purchased power, revenue and operating and maintenance expense, respectively.


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

Unrealized mark-to-market	$	103		$	1	$	(53	)	$	51
Realized mark-to-market		(12	)		2		—			(10	)

Total net mark-to-market	$	91		$	3	$	(53	)	$	41


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

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


Nine Months Ended September 30, 2006	Generation		ComEd(a)			Other(b)			Exelon

Unrealized mark-to-market	$	77	$	(8	)	$	(12	)	$	57
Realized mark-to-market		50		3			—			53

Total net mark-to-market	$	127	$	(5	)	$	(12	)	$	110


(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 September 30, 2005	Generation			ComEd		Other(a)		Exelon

Unrealized mark-to-market	$	168		$	—	$	11	$	179
Realized mark-to-market		(82	)		—		—		(82	)

Total net mark-to-market	$	86		$	—	$	11	$	97


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

Nine Months Ended September 30, 2005
Generation ComEd Other(a) Exelon

Unrealized mark-to-market
$ 192 $ — $ 28 $ 220

Realized mark-to-market
(65 ) — — (65 )

Total net mark-to-market
$ 127 $ — $ 28 $ 155


(a)		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 Management 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 are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For the three and nine months ended September 30, 2006 and 2005, Exelon and Generation recognized the following net unrealized mark-to-market gains, realized mark-to-market (losses) and total 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 financial trading are reported as revenue in Exelon’s Consolidated Statements of Operations and Comprehensive Income.


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2006			2005			2006			2005

Unrealized mark-to-market	$	10		$	4		$	14		$	14
Realized mark-to-market		(5	)		(2	)		(9	)		(3	)

Total net mark-to-market	$	5		$	2		$	5		$	11

Credit Risk Associated with Derivative Instruments (Exelon and Generation)

Exelon would be exposed to credit-related losses in the event of non-performance by counterparties that issue 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 has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Exelon’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.

18. Subsequent Events (Exelon and ComEd)

On October 2, 2006, ComEd reopened the First Mortgage 5.95% Bonds, Series 104, due August 15, 2016 and issued an additional $115 million. The proceeds of the bonds were used to pay the majority of the $95 million First Mortgage 8.25% Bonds due October 1, 2006 and the $31 million First Mortgage 8.375% Bonds due October 15, 2006 at maturity.

On October 26, 2006, Exelon, PECO and Generation entered into new unsecured credit facilities of $1 billion, $600 million and $5 billion, respectively. These facilities will be used for general corporate purposes, letters of credit issuances and commercial paper back-up. The facilities are for a term of five years and are comprised of three separate facilities with separate borrowers designated by Registrant. The new credit facilities will replace the existing $500 million and $1 billion Exelon syndicated facilities, the $1.95 billion in Generation bilateral credit facilities and Exelon’s $300 million term loan.


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 reportable segments:


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

	•	PECO, whose businesses include 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.

	•	Generation, which consists principally of the electric generating facilities, wholesale energy marketing operations, competitive retail sales and certain other generation projects.

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

Exelon’s corporate operations, 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 loss was $(44) million for the three months ended September 30, 2006 as compared to net income of $725 million for the same period in 2005 and Exelon’s loss per average common share was $(0.07) for the three months ended September 30, 2006 as compared to earnings per average diluted common share of $1.07 for the same period in 2005.

Exelon’s net income was $1,000 million for the nine months ended September 30, 2006 as compared to $1,760 million for the same period in 2005 and earnings per average diluted common share were $1.48 for the nine months ended September 30, 2006 and $2.60 for the same period in 2005.

The decrease in net income for both the three and nine months ended September 30, 2006 was primarily due to the following (amounts pre-tax):


	•	a $776 million impairment charge associated with ComEd’s goodwill primarily due to the impacts of the July 2006 Illinois Commerce Commission (ICC) rate order;

	•	a charge of approximately $55 million for the write-off of capitalized costs associated with the recently terminated proposed merger with Public Service Enterprise Group Incorporated (PSEG);

	•	increased severance and severance-related charges;

	•	unfavorable weather conditions in the ComEd and PECO service territories for the nine months ended September 30, 2006;

	•	reduced earnings from investments in synthetic fuel-producing facilities and, for the nine-month period, the impairment of the associated intangible asset recorded in the second quarter of 2006;

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


	•	higher operating and maintenance expenses, including increased costs associated with storm damage in the PECO service territory in the third quarter of 2006, expenses related to stock-based compensation as a result of adopting Financial Accounting Standards Board Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R) and the impacts of inflation;

	•	increased interest expense associated with the debt issued in March 2005 to fund Exelon’s pension contributions; and

	•	gains realized in 2005 on AmerGen’s decommissioning trust fund investments related to changes to the investment strategy.

The factors driving the overall decrease in net income above were partially offset by the following:


	•	higher margins on Generation’s wholesale market sales;

	•	a one-time benefit of approximately $130 million to recover certain costs approved by the ICC rate order;

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

	•	a decrease in Generation’s nuclear asset retirement obligation recorded in the second quarter of 2006 resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily the AmerGen nuclear plants;

	•	a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims;

	•	increased electric revenues at PECO associated with certain scheduled rate increases; and

	•	increased kilowatthour (kWh) deliveries, excluding the effects of weather, reflecting year-to-date load growth at ComEd and PECO.

Termination of Proposed Merger with PSEG. On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with PSEG, a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would be merged with and into Exelon (Merger). On September 14, 2006, Exelon gave formal notice to PSEG that Exelon had terminated the Merger Agreement and the companies agreed to withdraw their application for Merger approval, which had been pending before the New Jersey Board of Public Utilities (NJBPU) for more than 19 months. The notice followed a number of discussions with state officials and other interested parties, which made clear that gaps separating the parties’ respective settlement positions were insurmountable. Major differences included, among other things, issues relating to rate concessions and market power mitigation.

Financing Activities. During the nine months ended September 30, 2006, Exelon met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including capital markets, and through bank borrowings. During the nine months ended September 30, 2006, ComEd and Generation entered into credit facilities totaling $1 billion and $1.95 billion, respectively. In addition, ComEd issued $325 million and $300 million of First Mortgage Bonds in March and August 2006, respectively, and PECO issued $300 million of First Mortgage Bonds in September 2006. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information on the credit facilities and the bond issuances as of September 30, 2006. See Note 18 of the Combined Notes to Consolidated Financial Statements for further information on the credit facilities and the bond issuances in October 2006.

Regulatory and Environmental Developments. The following significant regulatory and environmental developments occurred during the nine months ended September 30, 2006. See Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements for further information.


	•	ComEd Procurement Filing — On January 24, 2006, the ICC approved ComEd’s procurement case, authorizing ComEd to procure electricity after 2006 through a “reverse-auction” competitive bidding process and to recover the costs from retail customers with no markup. The first auction took place in September 2006. As a result of the auction, ComEd has entered into supplier forward contracts with various suppliers. The ICC order is under appeal.


	•	ComEd Rate Case (Rate Case) — In 2005, ComEd made a rate case filing seeking to review its tariff and to adjust ComEd’s rates for delivering electricity to users in its service area, effective January 2007, in order to reflect ComEd’s rising costs and significant capital investment in its delivery system. ComEd proposed a revenue increase of $317 million. On June 8, 2006, the administrative law judges issued a proposed order, which included a revenue increase of $164 million plus ComEd’s request for recovery of several items which previously were recorded as expense. On July 26, 2006, the ICC issued its order in the Rate Case which approved a revenue increase of $8 million. The ICC rate order did approve ComEd’s requested recovery of several items, which previously were recorded as expense. However, the ICC disallowed rate base treatment (return) for ComEd’s prepaid pension asset, net of deferred taxes, of $639 million, and disallowed the recovery of certain administrative and general expenses. These disallowances will not result in an immediate write-off since the prepaid pension asset will be recovered as pension cost is recognized and recovered from customers in the future but will reduce ComEd’s future return on equity until the asset is recovered. The ICC rate order also provided for lower returns on rate base than ComEd had requested. On August 30, 2006, the ICC granted in part, and denied in part, ComEd’s request for rehearing. Other parties also filed requests for rehearing which were granted in part and denied in part. Items to be considered in that rehearing include administrative and general expenses, general and intangible plant, prepaid pension asset, capital structure and the allowed return on equity. The rehearing process may take up to five months to complete but is currently scheduled to be completed by the end of 2006. ComEd or any other party may appeal the Rate Case if it is not satisfied with the results on rehearing. ComEd intends to do so if disallowances contained in the original ICC rate order are not changed on rehearing. If an appeal of the Rate Case is successful, any resulting adjustments to ComEd’s rates would have only a prospective effect and would not be retroactive. Due to the significant negative impact of the ICC rate order to the cash flows and value of ComEd, ComEd was required to perform an interim impairment assessment during the third quarter of 2006 which resulted in recording an after-tax impairment charge of $776 million associated with the write-off of goodwill. Under GAAP, 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 may be impaired, such as a significant negative regulatory outcome. As of September 30, 2006 and December 31, 2005, Exelon and ComEd both had goodwill of approximately $2.7 billion and $3.5 billion, respectively.

	•	ComEd Residential Rate Stabilization — ComEd filed a residential rate stabilization proposal in 2006 to ease residential customers’ transition after 2006 to cost-based rates from frozen rates, which would require regulatory approval to implement. The proposal includes an “opt-in” feature to give customers the choice to participate in the program. Average annual residential rate increases would be capped at 10% in 2007, 2008 and 2009 for customers choosing to participate in the program. For those customers, costs that exceed the caps would be deferred and recovered with carrying charges of 6.5% over three years from 2010 to 2012. 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 plan would terminate under a force majeure event, upon a ComEd bankruptcy, or if ComEd’s senior unsecured credit rating for at least one of the three major credit rating agencies falls below investment grade. Although the action by Standard & Poor’s Corporation (S&P) on October 5, 2006 to lower ComEd’s senior unsecured credit ratings to below investment grade would, if the program were in effect, result in termination of the program, ComEd has asked the ICC to continue to consider the proposal because S&P has indicated it may reevaluate its ratings on ComEd if no rate freeze legislation is passed. On October 20, 2006, the administrative law judge reviewing the residential rate stabilization program issued a proposed order which is consistent with ComEd’s proposal for this program. However, the ultimate outcome is uncertain pending the final ICC order and the status of ComEd’s credit ratings.

	•	Illinois Rate Freeze Extension Proposal — On February 24, 2006, House Bill 5766 was introduced in the Illinois General Assembly and was referred to the Rules Committee. House Bill 5766, if enacted, would extend the current rate freeze in Illinois until at least 2010. The Illinois General Assembly took no action on the bill and is now adjourned. It is scheduled to resume session in November 2006. In light of the power supply auction results, there have recently been renewed efforts to pass similar legislation as part of Senate Bill 1714, which was approved by the House Electric Utility Oversight Committee. ComEd believes the proposed legislation, if enacted into law, would have serious detrimental effects on Illinois, ComEd and


		consumers of electricity. ComEd believes the proposed rate freeze extension, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such enacted rate freeze legislation in court.


	•	Nuclear Fleet Inspection — In February 2006, Exelon and Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium into the environment. The initiative was in response to the detection of tritium in water samples taken related to leaks at the Braidwood, Byron and Dresden nuclear generating stations in Illinois. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood where past accidental tritiated water spills have been identified and state-approved cleanup work continues. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors.

Outlook for 2006 and Beyond. Exelon’s future financial results will be affected by a number of factors, including the following:


	•	Certain governmental officials and consumer advocacy groups claim that ComEd’s retail rates for electricity should not be based solely on its cost to procure electricity in the wholesale market. If the price at which ComEd is allowed to sell electricity beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there will be material adverse consequences to ComEd, which could result in material adverse consequences to Exelon and, in the event of a ComEd bankruptcy filing, possibly material adverse consequences to Generation. However, the ICC’s unanimous approval of the reverse-auction process, barring any successful appeals or change in law, should provide ComEd with stability and greater certainty that it will be able to procure electricity and pass through the costs of that electricity to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction competitive bidding process.

	•	PECO is subject to electric rate caps on its transmission and distribution rates through December 31, 2006 and on its generation rates through December 31, 2010. PECO’s transmission and distribution rates will continue in effect after the expiration of the caps 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, however, 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 are designed to fully recover PECO’s applicable costs on a dollar-for-dollar basis.

	•	Effective January 1, 2007, in accordance with its 1998 restructuring settlement with the Pennsylvania Public Utility Commission (PAPUC), PECO will implement an electric generation rate increase resulting in approximately $190 million of additional operating revenues in 2007 as compared to 2006 and a corresponding increase in purchased power from affiliate, in accordance with PECO’s purchased power agreement (PPA) with Generation, with no resulting impact on pre-tax operating income. The impact of this rate increase on Exelon will be an increase in operating revenues and pre-tax operating income of approximately $190 million. The impact on Generation will be an increase in operating revenues from affiliates and pre-tax operating income of approximately $190 million.

	•	The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. Generally, between 60% and 70% of Generation’s supply currently serves ComEd and PECO customers. Consequently, Generation has historically limited its earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations. Following the expiration of the PPA with ComEd at the end of 2006, Generation will be exposed to increased commodity price risk associated with the electricity historically sold to serve ComEd’s load obligations that will now be sold at market-based prices and will continue to be exposed to fluctuations in commodity prices for electricity after 2006 for the unhedged portion of its electricity trading portfolio. This increase in risk is partially mitigated by the


		reduction of risks attributable to peaking costs associated with the prior load obligations under the ComEd PPA that expires at the end of 2006. For 2007, Generation has hedges in place that result in a Midwest risk profile similar to previous years. Generation has been and will continue to be proactive in looking for hedging strategies to mitigate this risk in subsequent years as well.


		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 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 ComEd and PECO’s requirements have improved due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants. As mentioned previously, due to the expiration of the PPA between ComEd and Generation, Exelon will increase the amount of power sold into the wholesale energy market. Based on recent increases in market prices and forward contracts entered into in 2006, power now being sold to ComEd is likely to be sold in 2007 at higher prices than the prices previously received as part of the PPA.


	•	Federal and state governing bodies have begun to introduce, and in some cases approve, legislation mandating the future use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal. The extent of the use of these renewable and alternative fuel sources varies by state and could change. The future requirement to use these renewable and alternative fuel sources for some portion of ComEd’s and PECO’s distribution sales could result in increased fuel costs and capital expenditures.

	•	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 these plans become effective, Exelon may incur costs to either further limit 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 in 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. Exelon has not decided to build a new nuclear plant. 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. Exelon expects to submit the application to the NRC for the combined construction and operating license in 2008.

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 2005 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.

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

On January 1, 2006, Exelon adopted SFAS No. 123-R, which requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost is measured on the fair value of the equity or liability instruments at the date of grant and amortized over the vesting period. The fair value of stock options on the date of grant is estimated using the Black-Scholes-Merton option-pricing model, which requires assumptions such as dividend yield, expected volatility, risk-free interest rate, expected life and forfeiture rate. The fair value of performance share awards granted in 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year, which requires assumptions regarding Exelon’s total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. See Note 3 of the Combined Notes to Consolidated Financial Statements for further information. If the actual results of the cash-settled performance share awards differ significantly from the estimates, the Consolidated Financial Statements could be materially affected.

Goodwill (Exelon and ComEd)

As of September 30, 2006, Exelon and ComEd had approximately $2.7 billion of goodwill, which related entirely to the goodwill recorded upon the acquisition of ComEd. Exelon and ComEd perform assessments for impairment of their goodwill at least annually, or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired. Application of the goodwill impairment test requires significant management judgments, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit. Exelon assesses goodwill impairment at its ComEd reporting unit; accordingly, any goodwill impairment charge at ComEd is fully reflected in Exelon’s results of operations.

In the assessment, Exelon and ComEd estimate the fair value of the ComEd reporting unit using a probability-weighted, discounted cash flow model with multiple scenarios. The fair value incorporates management’s assessment of current events and expected future cash flows, including interest rates, utility sector market performance, changes in regulatory environments, recent regulatory filings and their results, operating and capital expenditure requirements and other factors. Changes in assumptions regarding these variables or in the assessment of how they interrelate could produce a different result, which could be material. Due to the significance of the ICC’s order in ComEd’s Rate Case to ComEd’s future results of operations, ComEd was required to perform an interim impairment assessment during the third quarter of 2006, which resulted in recording an impairment charge of $776 million associated with the write-off of the goodwill. Exelon and ComEd will complete their annual assessment of goodwill in the fourth quarter of 2006 at which time an additional impairment may be required. See Note 5 — Regulatory Issues for further discussions related to the Illinois regulatory environment and Note 6 — Intangible Assets for further discussion on goodwill.

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 September 30, 2006 Compared To Three Months Ended September 30, 2005


	Three Months
	Ended						Favorable
	September 30,						(Unfavorable)
Exelon Corporation	2006			2005			Variance

Operating revenues	$	4,401		$	4,473		$	(72	)
Operating expenses
Purchased power and fuel expense		1,485			1,692			207
Operating and maintenance expense		1,084			900			(184	)
Depreciation and amortization		400			358			(42	)
Impairment of goodwill		776			—			(776	)
Taxes other than income		218			211			(7	)

Total operating expenses		3,963			3,161			(802	)

Operating income		438			1,312			(874	)
Other income and deductions		(117	)		(244	)		127

Income (loss) from continuing operations before income taxes		321			1,068			(747	)
Income taxes		366			344			(22	)

Income (loss) from continuing operations		(45	)		724			(769	)
Income from discontinued operations, net of income taxes		1			1			—

Net income (loss)	$	(44	)	$	725		$	(769	)

Diluted earnings (loss) per share	$	(0.07	)	$	1.07		$	(1.14	)

Net Income (Loss). Exelon’s net loss for the three months ended September 30, 2006 reflects a $776 million impairment charge associated with ComEd’s goodwill; a pre-tax charge of approximately $55 million for the write-off of capitalized costs associated with the recently terminated proposed Merger with PSEG; increased severance and severance-related charges; unfavorable weather conditions in both the ComEd and PECO service territories; reduced earnings from investments in synthetic fuel-producing facilities; increased depreciation and amortization expense, including CTC amortization at PECO; and higher operating and maintenance expenses due to increased costs associated with storm damage in the PECO service territory, increased stock-based compensation expense, and the impacts from inflation. These decreases were partially offset by a pre-tax one-time benefit of approximately $130 million to recover certain costs approved by the ICC rate order; higher realized prices on market sales and increased nuclear output at Generation; and increased electric revenues at PECO associated with certain authorized rate increases.

Operating Revenues. Operating revenues decreased due to unfavorable weather conditions in the ComEd and PECO service territories relative to 2005. This decrease was partially offset by an increase in wholesale and retail electric sales at Generation due to an increase in market prices and electric rate increases at PECO. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased due to lower volumes of power purchased in the market and decreased fossil generation, partially offset by overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 25% of Generation’s total supply for the three months ended September 30, 2006 compared to 28% for the three months ended September 30, 2005. See further analysis and discussion of purchased power and fuel expense by segment below.

compensation expense, and the impacts from inflation. 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 and additional plant placed in service.

Impairment at ComEd. During the third quarter of 2006, ComEd recorded a $776 million goodwill impairment charge.

Taxes Other Than Income. Taxes other than income remained relatively constant for the three months ended September 30, 2006 compared to the same period in 2005.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 114.0% for the three months ended September 30, 2006 compared to 32.2% for the three months ended September 30, 2005. Exclusive of the goodwill impairment charge, the effective tax rate for the three months ended September 30, 2006 was 33.4%. 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). 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 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations. The results of Sithe are included in the Generation discussion below.

Income from discontinued operations remained constant for the three months ended September 30, 2006 compared to the three months ended September 30, 2005.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the three months ended September 30, 2006 compared to the same period in 2005 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
	September 30,					(Unfavorable)
	2006			2005		Variance

ComEd	$	(506	)	$	224	$	(730	)
PECO		134			166		(32	)
Generation		393			334		59
Other(a)		(66	)		—		(66	)

Total	$	(45	)	$	724	$	(769	)


(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


	Three Months Ended					Favorable
	September 30,					(Unfavorable)
	2006			2005		Variance

ComEd	$	(506	)	$	224	$	(730	)
PECO		134			166		(32	)
Generation		394			335		59
Other(a)		(66	)		—		(66	)

Total	$	(44	)	$	725	$	(769	)


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

Results of Operations — ComEd


	Three Months Ended						Favorable
	September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	1,840		$	1,948		$	(108	)
Operating expenses
Purchased power		994			1,082			88
Operating and maintenance		210			211			1
Impairment of goodwill		776			—			(776	)
Depreciation and amortization		115			111			(4	)
Taxes other than income		83			81			(2	)

Total operating expenses		2,178			1,485			(693	)

Operating income (loss)		(338	)		463			(801	)

Other income and deductions
Interest expense, net		(78	)		(71	)		(7	)
Equity in losses of unconsolidated affiliates		(2	)		(3	)		1
Other, net		89			(10	)		99

Total other income and deductions		9			(84	)		93

Income (loss) before income taxes		(329	)		379			(708	)
Income taxes		177			155			(22	)

Net income (loss)	$	(506	)	$	224		$	(730	)

Net Income. ComEd’s net income for the three months ended September 30, 2006 compared to the same period in 2005 reflects an impairment of goodwill and lower operating revenues partially offset by lower purchased power expense and one-time benefits associated with reversing previously incurred expenses as a result of the July 2006 ICC rate order as more fully described below.

Operating Revenues. The changes in operating revenues for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Weather	$	(95	)
Customer choice		(43	)
Volume		17
Rate changes and mix		5

Retail revenue		(116	)
Wholesale and miscellaneous revenues		6
Mark-to-market wholesale contract		2

Decrease in operating revenues	$	(108	)

Weather. Revenues were lower due to unfavorable weather conditions for the three months ended September 30, 2006 compared to the same period in 2005. 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 in non-summer months reduces demand. In ComEd’s service territory, cooling degree days were 12% lower during the three months ended September 30, 2006 compared to the same period in 2005.

Customer choice. For the three months ended September 30, 2006 and 2005, 25% and 19%, respectively, of energy delivered to ComEd’s retail customers was provided by alternative electric suppliers. Most of the customers previously receiving energy under the Purchase Power Option (PPO) are now electing either to buy their power from an alternative electric supplier or from ComEd under bundled rates.

All ComEd customers have the choice to purchase energy from an alternative electric supplier. This choice does not affect the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. As of September 30, 2006, one alternative electric supplier was approved to serve residential customers in the ComEd service territory. However, no residential customers have selected this alternative electric supplier.


	Three Months Ended
	September 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)		6,301			5,176
Percentage of total retail deliveries		25	%		19	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end		12,900			21,500
Percentage of total retail customers		(b	)		(b	)
Volume (GWhs)(a)		6,500			8,367
Percentage of total retail deliveries		25	%		31	%


(a)		One GWh is the equivalent of one million kWh.

(b)		Less than one percent.

Volume. The amount of revenues attributable to volume, exclusive of weather effects, was higher for the three months ended September 30, 2006 compared to the same period in 2005 due primarily to an increase in the number of customers.

Rate changes and mix. The increase in revenue related to rate and mix changes represents differences in year-over-year consumption between various customer classes offset by a decline in the CTC paid by customers of alternate electric suppliers due to the increase in market energy prices. The average rate paid by various customers is dependent on the amount and time of day that the power is consumed. Changes in customer consumption patterns, including increased usage, can result in an overall decrease in the average rate even though the tariff or rate schedule remains unchanged.

Wholesale and miscellaneous revenues. The wholesale and miscellaneous revenues increase primarily reflects an increase in transmission revenue reflecting increased peak and kWh load within the ComEd service territory.

Mark-to-market wholesale contract. Market-to-market wholesale revenues reflect a mark-to-market increase associated with one wholesale contract that had previously been recorded as a normal sale under SFAS No. 133, “Accounting For Derivatives and Hedging Activities” (SFAS No. 133) in 2005. This contract expires in December 2007.

Purchased Power Expense. The changes in purchased power expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Customer choice	$	(43	)
Weather		(40	)
Prices		(16	)
SECA rates		7
Volume		3
Other		1

Decrease in purchased power expense	$	(88	)

Customer choice. The decrease in purchased power expense from customer choice was primarily due to more ComEd non-residential customers electing to purchase energy from an alternative electric supplier.

Weather. The decrease in purchased power expense attributable to weather was due to unfavorable weather conditions in the ComEd service territory relative to the prior year.

Prices. Purchased power decreased due to the decrease in contracted energy prices under the PPA that ComEd has with Generation. The current PPA contract was entered into in March 2004 and reflects forward power prices in existence at that time. The PPA terminates at the end of 2006 and is expected to be replaced with the reverse-auction process approved by the ICC in January of this year. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the reverse-auction process.

Seams Elimination Charge/Cost Adjustment/Assignment (SECA) rates. Effective December 1, 2004, PJM Interconnection, LLC (PJM) became obligated to pay 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, the 2005 purchased power expense was lower than 2006 due to the expiration of SECA charges on March 31, 2006. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

Volume. The amount of purchased power attributable to volume increased as a result of increased usage by ComEd-supplied customers on a weather normalized basis versus the same period in 2005.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

ICC rate order(a)	$	(45	)
Severance-related expenses		13
Fringe benefits(b)		9
Customers’ Affordable Reliable Energy (CARE) program(c)		6
Incremental storm costs		4
Environmental-related costs		3
Wages and salaries		3
PSEG merger integration costs		1
Other		5

Decrease in operating and maintenance expense	$	(1	)


(a)		As a result of the July 2006 ICC rate order, ComEd recorded one-time benefits reversing previously incurred expenses including manufactured gas plant (MGP) costs and procurement case costs. See Notes 5 and 13 of the Combined Notes to the Consolidated Financial Statements for additional information.

(b)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $5 million and increased pension and other postretirement benefits costs of $6 million.

(c)		See Note 5 of the Combined Notes to the Consolidated Financial Statements for additional information.

Impairment of Goodwill. During the third quarter of 2006, ComEd completed a required interim assessment of goodwill for impairment purposes to reflect the adverse effects of the ICC’s July 2006 rate order. The assessment compared the carrying value of goodwill to the estimated fair value of goodwill as of a point in time. The estimated fair value incorporates management’s assessment of current events and expected future cash flows. The test indicated that ComEd’s goodwill was impaired and a charge of $776 million was recorded. After reflecting the impairment, ComEd had approximately $2.7 billion of goodwill recorded as of September 30, 2006.

Depreciation and Amortization Expense. The changes in depreciation and amortization expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase

Depreciation expense associated with higher plant balances	$	3
Other amortization expense		1

Increase in depreciation and amortization expense	$	4

Taxes Other Than Income. Taxes other than income remained constant for the three months ended September 30, 2006 compared to the same period in 2005.

Interest Expense, Net. The $7 million increase in interest expense, net for the three months ended September 30, 2006 compared to the same period in 2005 primarily resulted from higher debt balances and higher interest rates.

Other, Net. The changes in other, net for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

ICC rate order(a)	$	87
Loss on settlement of 2005 cash flow swaps		15
Other		(3	)

Increase in other, net	$	99


(a)		As a result of the July 2006 ICC rate order, ComEd recorded a one-time benefit associated with reversing previously incurred expenses to retire debt early. See Notes 5 and 13 of the Combined Notes to the Consolidated Financial Statements for additional information.

Income Taxes. The effective income tax rate was (53.8)% for the three months ended September 30, 2006 compared to 40.9% for the three months ended September 30, 2005. Exclusive of the goodwill impairment charge, the effective rate for the three months ended September 30, 2006 was 39.6%. 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 September 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		8,656		9,847		(1,191	)		(12.1	)%
Small commercial & industrial		6,917		5,872		1,045			17.8	%
Large commercial & industrial		3,032		2,024		1,008			49.8	%
Public authorities & electric railroads		577		496		81			16.3	%

Total full service		19,182		18,239		943			5.2	%

PPO
Small commercial & industrial		144		1,667		(1,523	)		(91.4	)%
Large commercial & industrial		55		1,524		(1,469	)		(96.4	)%

		199		3,191		(2,992	)		(93.8	)%

Delivery only(b)
Small commercial & industrial		1,748		1,391		357			25.7	%
Large commercial & industrial		4,553		3,785		768			20.3	%

		6,301		5,176		1,125			21.7	%

Total PPO and delivery only		6,500		8,367		(1,867	)		(22.3	)%

Total retail deliveries		25,682		26,606		(924	)		(3.5	)%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers electing to receive generation service from an alternative electric supplier.

100


	Three Months
	Ended September 30,
Electric Revenue	2006		2005		Variance			% Change

Full service(a)
Residential	$	802	$	903	$	(101	)		(11.2	)%
Small commercial & industrial		584		492		92			18.7	%
Large commercial & industrial		181		115		66			57.4	%
Public authorities & electric railroads		36		31		5			16.1	%

Total full service		1,603		1,541		62			4.0	%

PPO(b)
Small commercial & industrial		15		120		(105	)		(87.5	)%
Large commercial & industrial		5		94		(89	)		(94.7	)%

		20		214		(194	)		(90.7	)%

Delivery only(c)
Small commercial & industrial		28		20		8			40.0	%
Large commercial & industrial		48		40		8			20.0	%

		76		60		16			26.7	%

Total PPO and delivery only		96		274		(178	)		(65.0	)%

Total electric retail revenues		1,699		1,815		(116	)		(6.4	)%
Wholesale and miscellaneous revenue(d)		139		133		6			4.5	%
Mark-to-market wholesale contract		2		—		2			n.m.

Total operating revenues	$	1,840	$	1,948	$	(108	)		(5.5	)%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariff rates which include the cost of energy and the cost of transmission and distribution of the energy.

(b)		Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC.

(c)		Delivery only revenues reflect revenue under tariff rates from customers electing to receive generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.


		n.m. Not meaningful

101

Results of Operations — PECO


	Three Months
	Ended						Favorable
	September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	1,379		$	1,322		$	57
Operating expenses
Purchased power and fuel		666			626			(40	)
Operating and maintenance		191			143			(48	)
Depreciation and amortization		204			159			(45	)
Taxes other than income		81			74			(7	)

Total operating expenses		1,142			1,002			(140	)

Operating income		237			320			(83	)

Other income and deductions
Interest expense, net		(66	)		(70	)		4
Equity in losses of unconsolidated affiliates		(2	)		(4	)		2
Other, net		11			2			9

Total other income and deductions		(57	)		(72	)		15

Income before income taxes		180			248			(68	)
Income taxes		46			82			36

Net income		134			166			(32	)
Preferred stock dividends		1			1			—

Net income on common stock	$	133		$	165		$	(32	)

Net Income. PECO’s net income for the three months ended September 30, 2006 compared to the same period in 2005 decreased primarily due to higher CTC amortization and higher operating and maintenance expense which reflects higher storm costs. Partially offsetting these factors were higher revenues, net of purchased power and fuel expense, and an investment tax credit refund and associated interest income. Higher net revenues reflect certain authorized electric rate increases, including a scheduled CTC rate increase, partially offset by lower net electric revenues as a result of unfavorable weather relative to the prior year. The increases in CTC amortization expense and CTC rates are in accordance with PECO’s 1998 restructuring settlement with the PAPUC. The increase in CTC amortization expense exceeded the increase in CTC revenues.

Operating Revenues. The changes in PECO’s operating revenues for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


							Total
							Increase
	Electric			Gas			(Decrease)

Rate increases	$	74		$	5		$	79
Customer choice		15			—			15
Volume		(24	)		1			(23	)
Weather		(18	)		—			(18	)
Other rate changes and mix		(11	)		—			(11	)

Retail revenue		36			6			42

Wholesale and miscellaneous revenues		19			(4	)		15

Increase in operating revenues	$	55		$	2		$	57

102

Rate increases. The increase in electric revenues attributable to electric rate increases reflects scheduled CTC and generation rate increases in accordance with PECO’s 1998 restructuring settlement with the PAPUC and the elimination of the aggregate $200 million electric distribution rate reductions over the period January 1, 2002 through December 31, 2005 (approximately $40 million in 2005) related to the PAPUC’s approval of the merger between PECO and ComEd. The increase in gas revenues was due to net increases 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 September 30, 2006 was 12% higher than the average rate for the same period in 2005.

Customer choice. For the three months ended September 30, 2006 and 2005, 2% and 5%, respectively, of energy delivered to PECO’s retail customers was provided by alternative electric suppliers.

All PECO customers have the choice to purchase energy from an alternative electric supplier. This choice does not affect the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. 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.


	Three Months Ended September 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end		36,700			65,500
Percentage of total retail customers		2	%		4	%
Volume (GWhs)(a)		204			516
Percentage of total retail deliveries		2	%		5	%


(a)		One GWh is the equivalent of one million kWh.

The increase in electric retail revenue associated with customer choice reflects customers from all customer classes returning to PECO as their electric supplier as a result of rising wholesale energy prices and a number of alternative electric suppliers exiting the market during 2005 and 2006.

Volume. The decrease in electric revenues as a result of lower delivery volume, exclusive of the effects of weather and customer choice, reflects decreased usage across all customer classes, partially offset by the favorable impact of an increased number of customers in the residential and small commercial and industrial classes.

Weather. 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 lower due to unfavorable weather conditions in PECO’s service territory, where cooling degree days were 18% lower during the three months ended September 30, 2006 compared to the same period in 2005.

Other rate changes and mix. The decrease in electric revenues attributable to other rate changes and mix reflects lower rates, primarily in September, for certain large commercial and industrial customers whose rates reflect wholesale energy prices.

Wholesale and miscellaneous revenues. The increase in electric revenues was primarily due to increased PJM transmission revenue and increased sales of energy into the PJM spot market. If PECO’s energy needs are less than the daily amount scheduled, the excess is sold into the PJM spot market. Revenues from these sales are reflected as adjustments to the billings under PECO’s PPA with Generation. The decrease in gas revenues was due to decreased off-system sales.

103

Purchased Power and Fuel Expense. The changes in PECO’s purchased power and fuel expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


							Total
							Increase
	Electric			Gas			(Decrease)

Prices	$	26		$	5		$	31
Customer choice		15			—			15
PJM transmission		7			—			7
Volume		(11	)		(4	)		(15	)
Weather		(8	)		—			(8	)
Other		11			(1	)		10

Increase in purchased power and fuel expense	$	40		$	—		$	40

Prices. PECO’s purchased power expense increased primarily due to the increase in electric revenues which was attributable to the scheduled generation rate increase. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Customer choice. The increase in purchased power expense from customer choice was primarily due to customers from all customer classes returning to PECO as their electric supplier, primarily as a result of rising wholesale energy prices and a number of alternative energy suppliers exiting the market during 2005 and 2006.

PJM transmission. The increase in PJM transmission expense reflects increased peak demand and consumption by PECO-supplied customers due to load growth as well as an increase in PECO-supplied customers driven by more customers choosing PECO for supply due to alternative suppliers’ higher market prices.

Volume. The decrease in purchased power expense attributable to volume, exclusive of the effects of weather and customer choice, reflects decreased usage across all customer classes, partially offset by the favorable impact of an increased number of customers in the residential and small commercial and industrial classes.

Weather. The decrease in purchased power and fuel expense attributable to weather was primarily due to lower demand as a result of unfavorable weather conditions in the PECO service territory relative to the prior year.

Other. The increase in electric purchased power expense was primarily due to increased energy purchases in the PJM spot market. If PECO’s energy needs are greater than the daily amount scheduled, the shortfall is secured through purchases in the PJM spot market. These additional costs are reflected as adjustments to the billings under PECO’s PPA with Generation.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Storm costs	$	32
Contractors(a)		17
Severance-related expenses		4
Allowance for uncollectible accounts		3
Fringe benefits(b)		(5	)
Injuries and damages		(5	)
Other		2

Increase in operating and maintenance expense	$	48


(a)		Reflects higher professional fees associated with tax consulting, including $6 million related to an investment tax credit refund in the third quarter of 2006, and various other increases. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment tax credit refund.

(b)		Reflects lower workers compensation expense in 2005 and increased stock-based compensation expense of $2 million in 2006.

104

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the three months ended September 30, 2006 compared to the same period in 2005 was primarily due to an increase in CTC amortization of $44 million. PECO’s additional amortization of the CTC is in accordance with its original settlement under the Pennsylvania Competition Act.

Taxes Other Than Income. The changes in taxes other than income for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase

Sales and use tax adjustment in 2005	$	3
Other		4

Increase in taxes other than income	$	7

Interest Expense, Net. The decrease in interest expense, net was primarily due to scheduled payments on long-term debt owed to PECO Energy Transition Trust (PETT), partially offset by an increase in interest rates on variable rate debt and an increased amount of commercial paper outstanding.

Other, Net. The increase was primarily due to interest income associated with an investment tax credit refund of $10 million in the third quarter of 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment tax credit refund. See Note 14 of the Combined Notes to the Consolidated Financial Statements for further details of the components of Other, Net.

Income Taxes. The effective income tax rate was 25.6% for the three months ended September 30, 2006 compared to 33.1% for the three months ended September 30, 2005. The lower effective rate in 2006 reflects an investment tax credit refund in the third quarter of 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment tax credit refund. 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
	September 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		3,787		4,075		(288	)		(7.1	)%
Small commercial & industrial		2,146		2,175		(29	)		(1.3	)%
Large commercial & industrial		4,455		4,214		241			5.7	%
Public authorities & electric railroads		217		222		(5	)		(2.3	)%

Total full service		10,605		10,686		(81	)		(0.8	)%

Delivery only(b)
Residential		17		95		(78	)		(82.1	)%
Small commercial & industrial		183		326		(143	)		(43.9	)%
Large commercial & industrial		4		95		(91	)		(95.8	)%

Total delivery only		204		516		(312	)		(60.5	)%

Total retail deliveries		10,809		11,202		(393	)		(3.5	)%


(a)		Full service reflects deliveries to customers taking electric service under tariff rates.

(b)		Delivery only service reflects customers receiving electric generation service from an alternative electric supplier.

105


	Three Months
	Ended
	September 30,
Electric Revenue	2006		2005		Variance			% Change

Full service(a)
Residential	$	570	$	578	$	(8	)		(1.4	)%
Small commercial & industrial		276		257		19			7.4	%
Large commercial & industrial		363		325		38			11.7	%
Public authorities & electric railroads		21		19		2			10.5	%

Total full service		1,230		1,179		51			4.3	%

Delivery only(b)
Residential		1		8		(7	)		(87.5	)%
Small commercial & industrial		11		17		(6	)		(35.3	)%
Large commercial & industrial		—		2		(2	)		(100.0	)%

Total delivery only		12		27		(15	)		(55.6	)%

Total electric retail revenues		1,242		1,206		36			3.0	%

Miscellaneous revenues(c)		68		49		19			38.8	%

Total electric and other revenue	$	1,310	$	1,255	$	55			4.4	%


(a)		Full service revenue reflects revenue from customers taking electric service under tariff rates which includes 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 an alternative electric supplier, which includes the cost of distribution of the energy and a CTC.

(c)		Miscellaneous 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
	September 30,
Deliveries to customers (in million cubic feet (mmcf))	2006		2005		Variance		% Change

Retail sales		3,950		3,786		164		4.3	%
Transportation		6,184		5,755		429		7.5	%

Total		10,134		9,541		593		6.2	%


	Three Months
	Ended
	September 30,
Revenue	2006		2005		Variance			% Change

Retail sales	$	64	$	58	$	6			10.3	%
Transportation		4		4		—			—
Resales and other		1		5		(4	)		(80.0	)%

Total gas revenue	$	69	$	67	$	2			3.0	%

106

Results of Operations — Generation


	Three Months Ended						Favorable
	September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	2,635		$	2,711		$	(76	)
Operating expenses
Purchased power and fuel		1,273			1,488			215
Operating and maintenance		574			537			(37	)
Depreciation and amortization		71			63			(8	)
Taxes other than income		49			48			(1	)

Total operating expenses		1,967			2,136			169

Operating income		668			575			93

Other income and deductions
Interest expense		(38	)		(33	)		(5	)
Equity in losses of unconsolidated affiliates		(5	)		(2	)		(3	)
Other, net		12			13			(1	)

Total other income and deductions		(31	)		(22	)		(9	)

Income from continuing operations before income taxes		637			553			84
Income taxes		244			219			(25	)

Income from continuing operations		393			334			59
Income from discontinued operations, net of income taxes		1			1			—

Net income	$	394		$	335		$	59

Net Income. Generation’s net income for the three months ended September 30, 2006 compared to the same period in 2005 increased due to higher revenue, net of purchased power and fuel expense, partially offset by higher operating and maintenance and depreciation expense. The quarter-over-quarter increase in revenue, net of purchased power and fuel expense, was driven by higher average margins on wholesale market sales due to more favorably-priced hedges, the impact of higher hydro and nuclear generation, lower purchased power costs and the contractual increase in prices associated with Generation’s power sales agreement with PECO, partially offset by the contractual decrease in prices associated with Generation’s power sales agreement with ComEd. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. The increase in operating and maintenance expense was primarily due to an increase in payroll-related expenses and nuclear refueling outage costs associated with the additional planned refueling outage days in the three months ended September 30, 2006 as compared to the same period in 2005.

107

Operating Revenues. For the three months ended September 30, 2006 and 2005, Generation’s sales were as follows:


	Three Months
	Ended
	September 30,
Revenue	2006		2005		Variance			% Change

Electric sales to affiliates	$	1,429	$	1,484	$	(55	)		(3.7	)%
Wholesale and retail electric sales		1,034		1,038		(4	)		(0.4	)%

Total electric sales revenue		2,463		2,522		(59	)		(2.3	)%
Retail gas sales		65		77		(12	)		(15.6	)%
Trading portfolio		10		4		6			n.m.
Other operating revenue(a)		97		108		(11	)		(10.2	)%

Total operating revenue	$	2,635	$	2,711	$	(76	)		(2.8	)%


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


		n.m. Not meaningful


	Three Months
	Ended
	September 30,
Sales (in GWhs)	2006		2005		Variance			% Change

Electric sales to affiliates		33,927		35,773		(1,846	)		(5.2	)%
Wholesale and retail electric sales		19,075		19,525		(450	)		(2.3	)%

Total electric sales		53,002		55,298		(2,296	)		(4.2	)%

Trading volumes of 8,909 GWhs and 6,757 GWhs for the three months ended September 30, 2006 and 2005, respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $55 million for the three months ended September 30, 2006 compared to the same period in 2005. The decrease in revenue from sales to affiliates was primarily due to a $74 million decrease from lower electric sales volume, partially offset by higher prices of $19 million. In the ComEd territories, lower volumes as a result of milder weather quarter over quarter and customers electing an alternative electric supplier resulted in a $70 million decrease in revenues. In addition, prices were lower as a result of lower peak prices under the ComEd PPA resulting in a $13 million decrease in revenues. In the PECO territories, the milder weather resulted in decreased volumes and revenues of $4 million, partially offset by a $32 million increase as a result of a change in the mix of average pricing related to the PPA with PECO.

Wholesale and retail electric sales. The decrease in Generation’s wholesale and retail electric sales for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Price	$	22
Volume		(26	)

Decrease in wholesale and retail electric sales	$	(4	)

Wholesale and retail electric sales decreased $4 million due to realized revenues associated with forward sales entered into in prior periods, which were recognized at higher prices for the three months ended September 30, 2006 compared to the same period in 2005, offset by a reduction in volumes sold into the market as a result of less generation in the fossil fuel units.

108

Retail gas sales. Retail gas sales decreased $12 million primarily due to lower realized prices and lower volumes for the three months ended September 30, 2006 as compared to the three months ended September 30, 2005.

Other revenue. The decrease in other revenue for the three months ended September 30, 2006 compared to the same period in 2005 was primarily due to a decrease in fossil fuel sales.

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


	Three Months
	Ended
	September 30,
Supply Source (in GWhs)	2006		2005		Variance			% Change

Nuclear generation(a)		35,867		35,584		283			0.8	%
Purchases — non-trading portfolio		13,341		15,393		(2,052	)		(13.3	)%
Fossil and hydroelectric generation		3,794		4,321		(527	)		(12.2	)%

Total supply		53,002		55,298		(2,296	)		(4.2	)%


(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 September 30, 2006 compared to the same period in 2005 consisted of the following:


							Increase
	Price			Volume			(Decrease)

Purchased power costs	$	(34	)	$	(153	)	$	(187	)
Generation cost		(17	)		(2	)		(19	)
Fuel resale cost		2			(6	)		(4	)
Mark-to-market		n.m.			n.m.			(5	)

Decrease in purchased power and fuel expense	$	(49	)	$	(161	)	$	(215	)


		n.m. Not meaningful

Purchased Power Cost. Purchased power cost includes all costs associated with the procurement of power (i.e., capacity, energy and fuel costs associated with tolling agreements). Generation experienced overall lower realized prices for purchased power in the three months ended September 30, 2006 compared to the prior year resulting in a $34 million decrease. Additionally, there was a decrease of $153 million in volumes primarily due to higher volumes produced by Generation’s nuclear units and less demand from affiliates.

Generation Cost. Generation cost includes fuel cost for internally generated energy. Generation experienced overall lower generation costs for the three months ended September 30, 2006 as compared to the same period in 2005 due to lower fossil fuel costs offset by higher nuclear fuel costs, as well as less generation from fossil units.

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 September 30, 2006 as compared to quarter ended 2005 consisted of overall higher realized gas prices, as well as overall higher prices for purchased fossil fuel. This is offset by a $6 million decrease in retail gas volumes.

Mark-to-market. Mark-to-market gains on power hedging activities were $53 million for the three months ended September 30, 2006 compared to losses of $7 million for the same period in 2005. Mark-to-market gains on fuel hedging activities were $38 million for the three months ended September 30, 2006 compared to gains of $93 million for the same period in 2005.

109

Generation’s average margin per MWh of electricity sold during the three months ended September 30, 2006 and 2005 were as follows:


	Three Months Ended
	September 30,
($/MWh)	2006		2005		% Change

Average electric revenue
Electric sales to affiliates	$	42.12	$	41.48		1.5	%
Wholesale and retail electric sales		54.21		53.16		2.0	%
Total — excluding the trading portfolio		46.47		45.61		1.9	%
Average electric supply cost (a) — excluding the trading portfolio		22.66		25.53		(11.2	)%
Average margin — excluding the trading portfolio		23.81		20.08		18.6	%


(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 three months ended September 30, 2006 and 2005 were as follows:


	Three Months
	Ended
	September 30,
	2006			2005

Nuclear fleet capacity factor(a)		95.8	%		95.0	%
Nuclear fleet production cost per MWh(a)	$	12.79		$	11.77


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor increased primarily due to fewer non-refueling outage days during the three months ended September 30, 2006 compared to the same period in 2005. For the three months ended September 30, 2006 and 2005, non-refueling outage days totaled 4 and 29, respectively, and refueling outage days totaled 35 and 16, respectively. Additionally, during the three months ended September 30, 2006, both Quad Cities units operated at Extended Power Uprate (EPU) generation levels as compared to the three months ended September 30, 2005, when one Quad Cities unit operated at pre-EPU generation levels until its steam dryer was replaced and extensive testing and load verification was completed. Costs associated with the additional planned refueling outage days, higher costs for refueling outage inspection and maintenance activities, costs for the fleet-wide tritium assessment project, an NRC fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated resulting in a higher production cost per MWh produced for the three months ended September 30, 2006 as compared to the same period in 2005. There were two planned refueling outages and two non-refueling outages that began during the three months ended September 30, 2006 compared to two planned refuel outage and five other outages that began during the three months ended September 30, 2005.

Operating and Maintenance Expense. The increase in operating and maintenance expense for the three months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Nuclear refueling outage costs	$	25
Pension, payroll and benefit costs		30
Decommissioning-related activity		(24	)
Other		6

Increase in operating and maintenance expense	$	37

110

This net $37 million increase is primarily attributable to the following:


	•	A $25 million increase in nuclear refueling outage costs associated with the additional planned refueling outage days during the three months ended September 30, 2006 as compared to the same period in 2005.

	•	A $30 million increase in various fringe benefits including increased stock-based compensation expense of $8 million and increased direct and allocated costs related to payroll, severance, pension and other postretirement benefits expense.

	•	A $24 million decrease in decommissioning-related activity expenses, primarily due to a $17 million credit, recorded in the third quarter of 2006, required to offset a deferred tax expense within income taxes. Together, these amounts had no net impact on results of operations for the three months ended September 30, 2006 as they offset in income tax expense.

Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended September 30, 2006 compared to the same period in 2005 was a result of recent capital additions.

Interest Expense. The increase in interest expense for the three months ended September 30, 2006 as compared to the same period in 2005 was attributable to higher variable interest rates on higher debt outstanding and higher interest expense on Generation’s one-time fee for pre-1983 spent nuclear fuel obligations to the Department of Energy.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 38.3% for the three months ended September 30, 2006 compared to 39.6% for the three months ended September 30, 2005. The decrease in the effective income tax rate was due to a decrease in the state income tax rate as a result of the treatment of state net operating losses (NOL) due to new Pennsylvania laws and the realization of the NOL benefits for the three months ended September 30, 2006 as compared to the same period in 2005. 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. Generation’s net income for the three months ended September 30, 2006 and 2005 both reflect a gain on the sale of discontinued operations of $1 million (after tax). 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 — Exelon Corporation

Nine Months Ended September 30, 2006 Compared To Nine Months Ended September 30, 2005


	Nine Months
	Ended						Favorable
	September 30,						(Unfavorable)
Exelon Corporation	2006			2005			Variance

Operating revenues	$	11,960		$	11,519		$	441
Operating expenses
Purchased power and fuel expense		4,020			4,040			20
Operating and maintenance expense		2,989			2,776			(213	)
Depreciation and amortization		1,135			1,003			(132	)
Impairment of goodwill		776			—			(776	)
Taxes other than income		582			560			(22	)

Total operating expenses		9,502			8,379			(1,123	)

Operating income		2,458			3,140			(682	)
Other income and deductions		(532	)		(614	)		82

Income from continuing operations before income taxes		1,926			2,526			(600	)
Income taxes		929			779			(150	)

Income from continuing operations		997			1,747			(750	)
Income from discontinued operations, net of income taxes		3			13			(10	)

Net income	$	1,000		$	1,760		$	(760	)

Diluted earnings per share	$	1.48		$	2.60		$	(1.12	)

Net Income. Exelon’s net income for the nine months ended September 30, 2006 reflects a $776 million impairment charge associated with ComEd’s goodwill; a pre-tax charge of approximately $55 million for the write-off of capitalized costs associated with the recently terminated proposed Merger with PSEG; increased severance and severance-related charges; unfavorable weather conditions in the ComEd and PECO service territories; reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset; increased depreciation and amortization expense, including CTC amortization at PECO; and higher operating and maintenance expenses due to increased costs associated with storm damage in the PECO service territory, increased stock-based compensation expense as a result of adopting SFAS No. 123-R, and the impacts of inflation. These decreases were partially offset by a pre-tax one-time benefit of approximately $130 million to recover certain costs approved by the ICC rate order; higher realized prices on market sales and increased nuclear output at Generation; a decrease in Generation’s nuclear asset retirement obligation (ARO) resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily AmerGen nuclear plants; unrealized mark-to-market gains; increased electric revenues at PECO associated with certain authorized rate increases; and increased kWh deliveries, excluding the effects of weather, reflecting load growth at ComEd and PECO. Exelon’s net income for the nine months ended September 30, 2005 reflects a charge for a reserve recorded by Generation for estimated future asbestos-related bodily injury claims; unrealized mark-to-market gains; a gain resulting from the sale of Exelon’s investment in Sithe; favorable real estate tax settlements at PECO and Generation; and gains realized on AmerGen’s decommissioning trust fund investments related to changes in the investment strategy.

Operating Revenues. Operating revenues increased primarily due to an increase in wholesale and retail electric sales and retail gas sales at Generation due to an increase in market prices; higher nuclear output; higher kWh deliveries at ComEd and PECO, excluding the effects of weather; and electric rate increases at PECO. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories. See further analysis and discussion of operating revenues by segment below.

112

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased due to lower volumes of power purchased in the market and decreased fossil generation, partially offset by overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 20% of Generation’s total supply for the nine months ended September 30, 2006 compared to 23% for the nine months ended September 30, 2005. 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 a charge of approximately $55 million for the write-off of capitalized costs associated with the recently terminated proposed Merger with PSEG; increased severance and severance-related charges; increased stock-based compensation expense as a result of adopting SFAS No. 123-R, and the impacts from inflation. These decreases were partially offset by the impact of the reduction in Generation’s nuclear asset retirement obligation; mark-to-market gains associated with Exelon’s investment in synthetic fuel-producing facilities; and a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims. See further discussion of operating and maintenance expenses by segment below.

Impairment at ComEd. During 2006, ComEd recorded a $776 million goodwill impairment charge.

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO and additional plant placed in service.

Taxes Other Than Income. Taxes other than income increased primarily due to a reduction in 2005 of previously established real estate tax reserves at PECO and Generation and a net increase in utility revenue taxes at ComEd and PECO partially offset by favorable state franchise tax settlements at PECO in 2006.

Other Income and Deductions. The change in other income and deductions reflects increased interest expense associated with the debt issued in 2005 to fund Exelon’s voluntary pension contribution; higher interest rates on variable rate debt outstanding; higher interest expense on Generation’s one-time fee for pre-1983 spent nuclear fuel obligations; and an interest payment associated with a tax resolution at Generation related to Sithe.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 48.2% for the nine months ended September 30, 2006 compared to 30.8% for the nine months ended September 30, 2005. Exclusive of the goodwill impairment charge, the effective tax rate for the nine months ended September 30, 2006 was 34.4%. The increase in the income tax rate is primarily due to the phase-out of the income tax credits associated with Exelon’s investments in synthetic fuel-producing facilities. 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 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations. The results of Sithe are included in the Generation discussion below.

The income from discontinued operations decreased by $10 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005 partially offset by an adjustment to the gain on the sale of Sithe in the second quarter of 2006 as a result of the expiration of certain tax indemnifications.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the nine months ended September 30, 2006 compared to the same period in 2005 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

113

Results of Operations — ComEd


	Nine Months						Favorable
	Ended September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	4,720		$	4,822		$	(102	)
Operating expenses
Purchased power		2,623			2,761			138
Operating and maintenance		644			614			(30	)
Impairment of goodwill		776			—			(776	)
Depreciation and amortization		320			308			(12	)
Taxes other than income		234			232			(2	)

Total operating expenses		4,597			3,915			(682	)

Operating income		123			907			(784	)

Other income and deductions
Interest expense, net		(230	)		(220	)		(10	)
Equity in losses of unconsolidated affiliates		(8	)		(11	)		3
Other, net		90			—			90

Total other income and deductions		(148	)		(231	)		83

Income before income taxes		(25	)		676			(701	)
Income taxes		300			273			(27	)

Net income (loss)	$	(325	)	$	403		$	(728	)

Net Income. ComEd’s net loss for the nine months ended September 30, 2006 compared to the same period in 2005 reflects an impairment of goodwill and lower operating revenues partially offset by lower purchased power expense and one-time benefits associated with reversing previously incurred expenses as a result of the July 2006 ICC rate order as more fully described below.

Operating Revenues. The changes in operating revenues for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Weather	$	(187	)
Customer choice		(12	)
Volume		64
Rate changes and mix		17

Retail revenue		(118	)

Wholesale and miscellaneous revenues		21
Mark-to-market wholesale contract		(5	)

Decrease in operating revenues	$	(102	)

Weather. Revenues were lower due to unfavorable weather conditions for the nine months ended September 30, 2006 compared to the same period in 2005. The demand for electricity is affected by weather conditions. In ComEd’s service territory, heating degree days were 8% lower and cooling degree days were 18% lower, during the nine months ended September 30, 2006 compared to the same period in 2005.

Customer choice. For the nine months ended September 30, 2006 and 2005, 22% and 21%, respectively, of energy delivered to ComEd’s retail customers was provided by alternative electric suppliers. Most of the customers

115

previously receiving energy under the PPO are now electing either to buy their power from an alternative electric supplier or from ComEd under bundled rates.


	Nine Months
	Ended September 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)		15,209			14,827
Percentage of total retail deliveries		22	%		21	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end		12,900			21,500
Percentage of total retail customers		(b	)		(b	)
Volume (GWhs)(a)		19,929			23,595
Percentage of total retail deliveries		29	%		34	%


(a)		One GWh is the equivalent of one million kWh.

(b)		Less than one percent.

Volume. Revenues were higher for the nine months ended September 30, 2006 compared to the same period in 2005 due primarily to an increase in deliveries, excluding the effects of weather, due to increased number of customers.

Mark-to-market wholesale contract. Market-to-market wholesale contract reflects a mark-to-market loss associated with one wholesale contract that had previously been recorded as a normal sale under SFAS No. 133 in 2005. This contract expires in December 2007.

116

Purchased Power Expense. The changes in purchased power expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Prices	$	(96	)
Weather		(92	)
Customer choice		(16	)
SECA rates		31
Volume		30
PJM transmission		3
Other		2

Decrease in purchased power expense	$	(138	)

Weather. The decrease in purchased power expense attributable to weather was due to unfavorable weather conditions in the ComEd service territory relative to prior year.

SECA rates. Effective December 1, 2004, PJM became obligated to pay 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. As a result of current events related to SECA disputes, during the first quarter of 2006, ComEd increased its reserve for amounts to be refunded. ComEd recorded SECA collections and payments on a net basis through purchased power expense. As ComEd was a net collector of SECA charges, the 2005 purchased power expense was lower than 2006 due to the expiration of SECA charges on March 31, 2006. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

Volume. The amount of purchased power attributable to volume increased as a result of increased usage by ComEd-supplied customers on a weather normalized basis versus the same period in 2005.

PJM transmission. The increase in PJM transmission expense reflects increased peak demand and consumption by ComEd-supplied customers partially offset by a decrease in ancillary charges.

117

Operating and Maintenance Expense. The changes in operating and maintenance expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Fringe benefits(a)	$	23
Severance-related expenses		15
Wages and salaries		12
CARE program(b)		7
PSEG merger integration costs		5
Rent and lease expense		4
Corporate allocations		3
ICC rate order(c)		(45	)
Other		6

Increase in operating and maintenance expense	$	30


(a)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $18 million primarily due to the adoption of SFAS No. 123-R on January 1, 2006 and increased pension and other postretirement benefits costs of $9 million.

(b)		See Note 5 of the Combined Notes to the Consolidated Financial Statements for additional information.

(c)		As a result of the July 2006 ICC rate order, ComEd recorded one-time benefits associated with reversing previously incurred expenses including MGP costs and procurement case costs. See Notes 5 and 13 of the Combined Notes to the Consolidated Financial Statements for additional information.

Impairment of Goodwill. During the third quarter of 2006, ComEd completed a required interim assessment of goodwill for impairment purposes to reflect the adverse affects of the ICC’s July 2006 rate order. The assessment compared the carrying value of goodwill to the estimated fair value of goodwill as of a point in time. The estimated fair value incorporates management’s assessment of current events and expected future cash flows. The test indicated that ComEd’s goodwill was impaired and a charge of $776 million was recorded. After reflecting the impairment, ComEd had approximately $2.7 billion of remaining goodwill as of September 30, 2006.

Depreciation and Amortization Expense. The changes in depreciation and amortization expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase

Depreciation expense associated with higher plant balances	$	8
Other amortization expense		4

Increase in depreciation and amortization expense	$	12

Taxes Other Than Income. Taxes other than income remained constant for the nine months ended September 30, 2006 compared to the same period in 2005.

Interest Expense, Net. The $10 million increase in interest expense, net for the nine months ended September 30, 2006 compared to the same period in 2005 primarily resulted from higher debt balances and higher interest rates.

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Other, Net. The changes in other, net for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

ICC rate order(a)	$	87
Loss on settlement of 2005 cash flow swaps		15
Loss on disposition of assets and investments, net		(4	)
Sale of receivable in 2005		(3	)
Other		(5	)

Increase in other, net	$	90


(a)		As a result of the July 2006 ICC rate order, ComEd recorded a one-time benefit associated with reversing previously incurred expenses to retire debt early. See Notes 5 and 13 of the Combined Notes to the Consolidated Financial Statements for additional information.

Income Taxes. The effective income tax rate was (1,200.0)% for the nine months ended September 30, 2006 compared to 40.4% for the nine months ended September 30, 2005. Exclusive of the goodwill impairment charge, the effective rate for the nine months ended September 30, 2006 was 39.9%. 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


	Nine Months
	Ended
	September 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		21,577		23,193		(1,616	)		(7.0	)%
Small commercial & industrial		17,945		16,083		1,862			11.6	%
Large commercial & industrial		7,641		5,907		1,734			29.4	%
Public authorities & electric railroads		1,692		1,548		144			9.3	%

Total full service		48,855		46,731		2,124			4.5	%

PPO
Small commercial & industrial		2,467		4,126		(1,659	)		(40.2	)%
Large commercial & industrial		2,253		4,642		(2,389	)		(51.5	)%

		4,720		8,768		(4,048	)		(46.2	)%

Delivery only(b)
Small commercial & industrial		3,933		4,554		(621	)		(13.6	)%
Large commercial & industrial		11,276		10,273		1,003			9.8	%

		15,209		14,827		382			2.6	%

Total PPO and delivery only		19,929		23,595		(3,666	)		(15.5	)%

Total retail deliveries		68,784		70,326		(1,542	)		(2.2	)%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers electing to receive generation service from an alternative electric supplier.

119


	Nine Months
	Ended September 30,
Electric Revenue	2006			2005		Variance			% Change

Full service(a)
Residential	$	1,899		$	2,027	$	(128	)		(6.3	)%
Small commercial & industrial		1,423			1,276		147			11.5	%
Large commercial & industrial		421			308		113			36.7	%
Public authorities & electric railroads		104			96		8			8.3	%

Total full service		3,847			3,707		140			3.8	%

PPO(b)
Small commercial & industrial		177			285		(108	)		(37.9	)%
Large commercial & industrial		137			265		(128	)		(48.3	)%

		314			550		(236	)		(42.9	)%

Delivery only(c)
Small commercial & industrial		61			78		(17	)		(21.8	)%
Large commercial & industrial		115			120		(5	)		(4.2	)%

		176			198		(22	)		(11.1	)%

Total PPO and delivery only		490			748		(258	)		(34.5	)%

Total electric retail revenues		4,337			4,455		(118	)		(2.6	)%
Wholesale and miscellaneous revenue(d)		388			367		21			5.7	%
Mark-to-market wholesale contract		(5	)		—		(5	)		n.m.

Total operating revenues	$	4,720		$	4,822	$	(102	)		(2.1	)%


(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates which include the cost of energy and the cost of transmission and distribution of the energy.

(b)		Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC.

(c)		Delivery only revenues reflect revenue under tariffed rates from customers electing to receive generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.


		n.m. Not meaningful

120

Results of Operations — PECO


	Nine Months
	Ended						Favorable
	September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	3,933		$	3,661		$	272
Operating expenses
Purchased power and fuel		2,056			1,827			(229	)
Operating and maintenance		479			396			(83	)
Depreciation and amortization		547			431			(116	)
Taxes other than income		198			189			(9	)

Total operating expenses		3,280			2,843			(437	)

Operating income		653			818			(165	)

Other income and deductions
Interest expense, net		(202	)		(211	)		9
Equity in losses of unconsolidated affiliates		(7	)		(12	)		5
Other, net		16			10			6

Total other income and deductions		(193	)		(213	)		20

Income before income taxes		460			605			(145	)
Income taxes		140			200			60

Net income		320			405			(85	)
Preferred stock dividends		3			3			—

Net income on common stock	$	317		$	402		$	(85	)

Net Income. PECO’s net income for the nine months ended September 30, 2006 compared to the same period in 2005 decreased primarily due to higher CTC amortization and higher operating and maintenance expense which reflects higher storm costs. Partially offsetting these factors were higher revenues, net of purchased power and fuel expense, and an investment tax credit refund and associated interest income. Higher net revenues reflect certain authorized electric rate increases, including a scheduled CTC rate increase, partially offset by lower net electric and gas revenues as a result of unfavorable weather relative to the prior year. The increases in CTC amortization expense and CTC rates are in accordance with PECO’s 1998 restructuring settlement with the PAPUC. The increase in CTC amortization expense exceeded the increase in CTC revenues.

Operating Revenues. The changes in PECO’s operating revenues for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


							Total
							Increase
	Electric			Gas			(Decrease)

Rate increases	$	178		$	161		$	339
Customer choice		52			—			52
Other rate changes and mix		4			—			4
Weather		(60	)		(82	)		(142	)
Volume		9			(12	)		(3	)

Retail revenue		183			67			250

Wholesale and miscellaneous revenues		31			(9	)		22

Increase in operating revenues	$	214		$	58		$	272

121

Rate increases. The increase in electric revenues attributable to electric rate increases reflects scheduled CTC and generation rate increases in accordance with PECO’s 1998 restructuring settlement with the PAPUC and the elimination of the aggregate $200 million electric distribution rate reductions over the period January 1, 2002 through December 31, 2005 (approximately $40 million in 2005) related to the PAPUC’s approval of the merger between PECO and ComEd. The increase in gas revenues was due to net increases 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 nine months ended September 30, 2006 was 37% higher than the average rate for the same period in 2005.

Customer choice. For the nine months ended September 30, 2006 and 2005, 2% and 6%, respectively, of energy delivered to PECO’s retail customers was provided by alternative electric suppliers.


	Nine Months
	Ended
	September 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end		36,700			65,500
Percentage of total retail customers		2	%		4	%
Volume (GWhs)(a)		610			1,738
Percentage of total retail deliveries		2	%		6	%


(a)		One GWh is the equivalent of one million kWh.

The increase in electric retail revenue associated with customer choice reflects customers from all customer classes returning to PECO as their electric supplier, primarily as a result of rising wholesale energy prices and a number of alternative electric suppliers exiting the market during 2005 and 2006.

Other rate changes and mix. The increase in electric revenues attributable to other rate changes and mix was primarily due to higher rates for certain large commercial and industrial customers whose rates reflect wholesale energy prices, which were higher in 2006 relative to 2005.

Weather. The demand for electricity and gas is affected by weather conditions. Revenues were lower due to unfavorable weather conditions in PECO’s service territory, where heating and cooling degree days were 18% and 14% lower, respectively, during the nine months ended September 30, 2006 compared to the same period in 2005.

Volume. The increase in electric revenues as a result of higher delivery volume, exclusive of the effects of weather and customer choice, was primarily due to an increased number of customers in the residential and small commercial and industrial classes and increased usage across all customer classes during the first half of 2006. The decrease in gas revenues attributable to lower delivery volume, exclusive of the effects of weather, was due to decreased customer usage, which is consistent with the impact of rising gas prices.

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Purchased Power and Fuel Expense. The changes in PECO’s purchased power and fuel expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


							Total
							Increase
	Electric			Gas			(Decrease)

Prices	$	80		$	161		$	241
Customer choice		52			—			52
PJM transmission		24			—			24
Weather		(26	)		(68	)		(94	)
Volume		—			(17	)		(17	)
Other		27			(4	)		23

Increase in purchased power and fuel expense	$	157		$	72		$	229

Prices. PECO’s purchased power expense increased $65 million corresponding to the increase in electric revenues which was attributable to the scheduled generation rate increase. In addition, PECO’s purchased power expense increased $15 million due to a change in the mix of average pricing related to its PPA with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Weather. The decrease in purchased power and fuel expense attributable to weather was primarily due to lower demand due to unfavorable weather conditions in the PECO service territory.

Volume. The decrease in gas fuel expense attributable to volume, exclusive of the effects of weather, was due to decreased customer usage, which is consistent with rising gas prices.

Operating and Maintenance Expense. The changes in operating and maintenance expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Storm costs	$	34
Allowance for uncollectible accounts(a)		23
Contractors(b)		15
Fringe benefits(c)		9
PSEG merger integration costs		4
Severance-related expenses		4
Environmental reserve(d)		(4	)
Other		(2	)

Increase in operating and maintenance expense	$	83


(a)		Reflects the following factors, all of which increased expense in 2006 as compared to 2005: (i) higher accounts receivable balances in 2006 compared to 2005 resulting from increased revenues; (ii) changes in PAPUC-approved regulations which

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		relaxed customer payment terms; and (iii) an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables.

(b)		Reflects higher professional fees associated with tax consulting, including $3 million in the second quarter of 2006 and $6 million related to an investment tax credit refund in the third quarter of 2006, and various other increases. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding tax consulting fees and the investment tax credit refund.

(c)		Reflects increased stock-based compensation expense of $8 million primarily due to the adoption of SFAS No. 123-R on January 1, 2006.

(d)		Represents a settlement related to one Superfund site in the first quarter of 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to an increase in CTC amortization of $112 million. PECO’s additional amortization of the CTC is in accordance with its original settlement under the Pennsylvania Competition Act.

Taxes Other Than Income. The changes in taxes other than income for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Taxes on utility revenues(a)	$	10
Real estate tax adjustment in 2005(b)		6
State franchise tax adjustment in 2006(c)		(7	)
Sales and use tax adjustments in 2006 and 2005		(2	)
Other		2

Increase in taxes other than income	$	9


(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. Includes a $3 million adjustment for the period 2001 through 2005.

(b)		Represents the reduction of a real estate tax accrual in the first quarter of 2005 following settlements related to prior year tax assessments.

(c)		Represents the reduction of tax accruals in the second quarter of 2006 following settlements related to prior year tax assessments.

Interest Expense, Net. The decrease in interest expense, net was primarily due to scheduled payments on long-term debt owed to PETT, partially offset by an increase in interest rates on variable rate debt and an increased amount of commercial paper outstanding.

Other, Net. The increase was primarily due to interest income associated with an investment tax credit refund of $10 million in the third quarter of 2006, partially offset by lower gains on disposition of assets. See Note 13 of the Combined Notes to Consolidated Financial Statement for additional information regarding the investment tax credit refund. See Note 14 of the Combined Notes to Consolidated Financial Statements for further details of the components of Other, Net.

Income Taxes. The effective income tax rate was 30.4% for the nine months ended September 30, 2006 compared to 33.1% for the nine months ended September 30, 2005. The lower effective tax rate in 2006 reflects an investment tax credit refund in the third quarter of 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment tax credit refund. See Note 10 of the Combined Notes to 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:


	Nine Months
	Ended
	September 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		9,703		10,030		(327	)		(3.3	)%
Small commercial & industrial		5,899		5,637		262			4.6	%
Large commercial & industrial		12,032		11,429		603			5.3	%
Public authorities & electric railroads		689		653		36			5.5	%

Total full service		28,323		27,749		574			2.1	%

Delivery only(b)
Residential		50		273		(223	)		(81.7	)%
Small commercial & industrial		528		1,038		(510	)		(49.1	)%
Large commercial & industrial		32		427		(395	)		(92.5	)%

Total delivery only		610		1,738		(1,128	)		(64.9	)%

Total retail deliveries		28,933		29,487		(554	)		(1.9	)%


(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.

(b)		Delivery only service reflects customers receiving electric generation service from an alternative electric supplier.


	Nine Months
	Ended
	September 30,
Electric Revenue	2006		2005		Variance			% Change

Full service(a)
Residential	$	1,365	$	1,322	$	43			3.3	%
Small commercial & industrial		722		643		79			12.3	%
Large commercial & industrial		978		871		107			12.3	%
Public authorities & electric railroads		63		59		4			6.8	%

Total full service		3,128		2,895		233			8.0	%

Delivery only(b)
Residential		4		21		(17	)		(81.0	)%
Small commercial & industrial		29		52		(23	)		(44.2	)%
Large commercial & industrial		1		11		(10	)		(90.9	)%

Total delivery only		34		84		(50	)		(59.5	)%

Total electric retail revenues		3,162		2,979		183			6.1	%

Miscellaneous revenues(c)		185		154		31			20.1	%

Total electric and other revenue	$	3,347	$	3,133	$	214			6.8	%


(a)		Full service revenue reflects revenue from customers taking electric service under tariffed rates which includes 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 an alternative electric supplier, which includes the cost of distribution of the energy and a CTC.

(c)		Miscellaneous 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:


	Nine Months
	Ended
	September 30,
Deliveries to Customers (in million cubic feet (mmcf))	2006		2005		Variance			% Change

Retail sales		35,163		41,318		(6,155	)		(14.9	)%
Transportation		19,203		19,319		(116	)		(0.6	)%

Total		54,366		60,637		(6,271	)		(10.3	)%


	Nine Months
	Ended
	September 30,
Revenue	2006		2005		Variance			% Change

Retail sales	$	570	$	503	$	67			13.3	%
Transportation		12		12		—			—
Resales and other		4		13		(9	)		(69.2	)%

Total gas revenue	$	586	$	528	$	58			11.0	%

Results of Operations — Generation


	Nine Months
	Ended						Favorable
	September 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	7,069		$	6,836		$	233
Operating expenses
Purchased power and fuel		3,091			3,241			150
Operating and maintenance		1,682			1,748			66
Depreciation and amortization		210			188			(22	)
Taxes other than income		133			122			(11	)

Total operating expenses		5,116			5,299			183

Operating income		1,953			1,537			416

Other income and deductions
Interest expense		(120	)		(91	)		(29	)
Equity in gains (losses) of unconsolidated affiliates		(9	)		2			(11	)
Other, net		31			82			(51	)

Total other income and deductions		(98	)		(7	)		(91	)

Income from continuing operations before income taxes		1,855			1,530			325
Income taxes		696			595			(101	)

Income from continuing operations		1,159			935			224
Income from discontinued operations, net of income taxes		4			16			(12	)

Net income	$	1,163		$	951		$	212

Net Income. Generation’s net income for the nine months ended September 30, 2006 compared to the same period in 2005 increased due to higher revenue, net of purchased power and fuel expense and lower operating and maintenance expense, partially offset by lower other income and higher interest expense and depreciation. The increase in Generation’s revenue, net of purchased power and fuel expense was related to realized revenues

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associated with forward sales entered into in prior periods which were recognized at higher prices, combined with lower purchased power and fuel expense due to the impact of higher nuclear output. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. The decrease in operating and maintenance expense was primarily due to the recognition of operating income in the second quarter of 2006 associated with the reduction in the nuclear ARO. Generation’s net income for the nine months ended September 30, 2006 and 2005 reflects income from discontinued operations of $4 million and $16 million (after tax), respectively.

Operating Revenues. For the nine months ended September 30, 2006 and 2005, Generation’s sales were as follows:


	Nine Months
	Ended
	September 30,
Revenue	2006		2005		Variance			% Change

Electric sales to affiliates	$	3,699	$	3,735	$	(36	)		(1.0	)%
Wholesale and retail electric sales		2,723		2,481		242			9.8	%

Total electric sales revenue		6,422		6,216		206			3.3	%
Retail gas sales		405		361		44			12.2	%
Trading portfolio		14		13		1			7.7	%
Other revenue(a)		228		246		(18	)		(7.3	)%

Total operating revenue	$	7,069	$	6,836	$	233			3.4	%


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


	Nine Months
	Ended
	September 30,
Sales (in GWhs)	2006		2005		Variance			% Change

Electric sales to affiliates		91,797		92,808		(1,011	)		(1.1	)%
Wholesale and retail electric sales		52,128		54,945		(2,817	)		(5.1	)%

Total sales		143,925		147,753		(3,828	)		(2.6	)%

Trading volumes of 23,664 GWhs and 18,168 GWhs for the nine months ended September 30, 2006 and 2005, respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $36 million for the nine months ended September 30, 2006 compared to the same period in 2005. The decrease in revenue from sales to affiliates was primarily due to a $38 million decrease from lower electric sales volume, partially offset by higher prices of $2 million. In the ComEd territories, lower volumes as a result of milder weather resulted in a $58 million decrease in revenues. In addition, prices were lower as a result of lower peak prices in the ComEd PPA resulting in a $92 million decrease in revenues. In the PECO territories, the increase of $94 million is a result of a change in the mix of average pricing related to the PPA with PECO. The remaining $20 million increase was due to higher volumes attributable to customer choice.

Wholesale and retail electric sales. The increase in Generation’s wholesale and retail electric sales for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Price	$	375
Volume		(133	)

Increase in wholesale and retail electric sales	$	242

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Wholesale and retail electric sales increased $242 million due to realized revenues associated with forward sales entered into in prior periods which were recognized at higher prices for the nine months ended September 30, 2006 compared to the same period in 2005, partially offset by lower volumes of generation capacity sold to the market.

Retail gas sales. Retail gas sales increased $44 million primarily due to higher realized prices partially offset by lower gas volumes.

Other revenue. The decrease in other revenue for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to a decrease in fossil fuel sales.

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


	Nine Months
	Ended
	September 30,
Supply Source (in GWhs)	2006		2005		Variance			% Change

Nuclear generation(a)		104,800		103,049		1,751			1.7	%
Purchases — non-trading portfolio		29,211		34,000		(4,789	)		(14.1	)%
Fossil and hydroelectric generation		9,914		10,704		(790	)		(7.4	)%

Total supply		143,925		147,753		(3,828	)		(2.6	)%


(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 nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


						Increase
	Price		Volume			(Decrease)

Purchased power costs	$	70	$	(338	)	$	(268	)
Generation cost		45		6			51
Fuel resale cost		99		(32	)		67
Mark-to-market		n.m.		n.m.			—

Decrease in purchased power and fuel expense	$	214	$	(364	)	$	(150	)


		n.m. Not meaningful

Purchased Power Cost. Purchased power cost includes all costs associated with the procurement of power (i.e., capacity, energy and fuel costs). Purchased power costs were lower in the three months ended September 30, 2006 as compared to the same period in 2005 due to lower volume resulting from reduced demand from affiliates and higher nuclear output. This decrease was partially offset by overall higher realized prices for purchased power in the nine months ended September 30, 2006 as compared to the same period in 2005.

Generation Cost. Generation cost includes fuel cost for internally generated energy. Generation experienced increased prices related to fossil fuel and nuclear generation for the nine months ended September 30, 2006 as compared to the same period in 2005, as well as increased nuclear generation. The increased volume expense of $6 million was primarily due to higher nuclear generation, offset by lower fossil fuel generation.

Fuel Resale Cost. Fuel resale cost includes all fuel costs associated with gas retail and wholesale fossil fuel expenses. The change in Generation’s gas supply costs for the nine months ended September 30, 2006 as compared to the same period in 2005 consisted of overall higher realized gas prices, as well as increased wholesale fossil fuel purchases. This increase is offset by a $32 million volume decrease that is primarily related to the gas retail business.

Mark-to-market. Mark-to-market gains on power hedging activities were $141 million for the nine months ended September 30, 2006 compared to losses of $11 million for the same period in 2005. Mark-to-market losses on

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fuel hedging activities were $14 million for the nine months ended September 30, 2006 compared to gains of $138 million for the same period in 2005.

Generation’s average margin per MWh of electricity sold during the nine months ended September 30, 2006 and 2005 were as follows:


	Nine Months
	Ended
	September 30,
($/MWh)	2006		2005		% Change

Average electric revenue
Electric sales to affiliates	$	40.30	$	40.24		0.1	%
Wholesale and retail electric sales		52.24		45.15		15.7	%
Total — excluding the trading portfolio		44.62		42.07		6.1	%
Average electric supply cost(a) — excluding the trading portfolio		18.61		19.59		(5.0	)%
Average margin — excluding the trading portfolio		26.01		22.48		15.7	%


(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 nine months ended September 30, 2006 and 2005 were as follows:


	Nine Months
	Ended
	September 30,
	2006			2005

Nuclear fleet capacity factor(a)		94.1	%		93.5	%
Nuclear fleet production cost per MWh(a)	$	13.71		$	12.73


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor increased due to fewer non-refueling outage days during the nine months ended September 30, 2006 compared to the same period in 2005. For the nine months ended September 30, 2006 and 2005, non-refueling outage days totaled 53 and 84, respectively, and refueling outage days totaled 149 and 144, respectively. Costs associated with the additional planned refueling outage days, higher costs for refueling outage inspection and maintenance activities, costs for the fleet-wide tritium assessment project, an NRC fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated resulting in a higher production cost per MWh produced for the nine months ended September 30, 2006 as compared to the same period in 2005. There were seven planned refueling outages and twelve non-refueling outages that began during the nine months ended September 30, 2006 compared to seven planned refueling outages and twenty non-refueling outages that began during the nine months ended September 30, 2005.

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Operating and Maintenance Expense. The decrease in operating and maintenance expense for the nine months ended September 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Reduction in ARO	$	(149	)
2005 accrual for estimated future asbestos-related bodily injury claims		(43	)
Other decommissioning-related activity		(25	)
Pension, payroll and benefit costs		98
Tritium related expense and NRC fees		22
Nuclear refueling outage costs		14
Contractors		11
Other		6

Decrease in operating and maintenance expense	$	(66	)

This net $66 million decrease is primarily attributable to the following:


	•	The recognition of operating income of $149 million which represents the reduction in the ARO balance for the AmerGen units (see further discussion in Note 11 of the Combined Notes to Consolidated Financial Statements).

	•	A $43 million liability established in June 2005 for estimated future asbestos-related bodily injury claims (see Note 13 to the Combined Notes to Consolidated Financial Statements for further discussion).

	•	A $25 million decrease in decommissioning-related activity expenses, primarily the result of a $17 million credit, recorded in the third quarter of 2006, required to offset a deferred tax expense within income taxes. Together, these amounts had no net impact on results of operations for the nine months ended September 30, 2006 as they offset in income tax expense.

	•	A $98 million increase in various payroll-related expenses includes increased stock-based compensation expense of $31 million primarily as a result of the adoption of SFAS No. 123-R as of January 1, 2006 and increased direct and allocated costs related to payroll, severance, pension and other postretirement benefits expense.

	•	A $22 million increase for tritium related expenses and increased NRC fees.

	•	A $14 million increase in nuclear refueling outage costs associated with the additional planned refueling outage days during the nine months ended September 30, 2006 as compared to the same period in 2005.

	•	An $11 million period-over-period increase in contractor costs, primarily related to staff augmentation and recurring maintenance work at Nuclear and Power.

Depreciation and Amortization. The increase in depreciation and amortization expense for the nine months ended September 30, 2006 compared to the same period in 2005 was a result of recent capital additions.

Taxes Other Than Income. The increase in taxes other than income for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to a reduction in 2005 of a previously established real estate reserve recorded during the first quarter of 2005 associated with the settlement over the Three Mile Island Nuclear Station real estate assessment, a property tax increase due to the increased assessment of Byron Station during the third quarter of 2006 and higher payroll related taxes which is the result of higher payroll costs for 2006. The increases were partially offset by a sales and use tax reserve recorded during the third quarter of 2005.

Interest Expense. The increase in interest expense for the nine months ended September 30, 2006 as compared to the same period in 2005 was attributable to variable interest rates on higher debt outstanding, higher interest expense on Generation’s one-time fee for pre-1983 spent nuclear fuel obligations to the Department of Energy and an interest payment made to the Internal Revenue Service (IRS) in settlement of a tax matter.

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Other, Net. The decrease in other income for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to gains realized in the second quarter of 2005 in the amount of $36 million related to the decommissioning trust fund investments for the AmerGen plants due to changes in Generation’s investment strategy and merger-related expenses recorded during the nine months ended September 30, 2006.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 37.5% for the nine months ended September 30, 2006 compared to 38.9% for the nine months ended September 30, 2005. The decrease in the effective income tax rate is due to a decrease in the state income tax rate as a result of the treatment of state NOL due to new Pennsylvania laws and the realization of the NOL benefits for the nine months ended September 30, 2006 as compared to the same period in 2005. 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. Generation’s net income for the nine months ended September 30, 2006 and 2005 reflects a gain on the sale of discontinued operations of $4 million and $16 million (both after tax), respectively. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the Presentation of Sithe as discontinued operations.

The income from discontinued operations decreased by $12 million for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005 partially offset by an adjustment to the gain on the sale of Sithe in the second quarter of 2006 as a result of the expiration of certain tax indemnifications, accrued interest and collections on receivables arising from the sale of Sithe that had been fully reserved.

Liquidity and Capital Resources

Capital resources are primarily provided by internally generated cash flows from operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing on reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that Exelon no longer has access to the capital markets at reasonable terms, Exelon, PECO and Generation have access to revolving credit facilities with aggregate bank commitments of $1.5 billion that they currently utilize to support their commercial paper programs. In addition, ComEd and Generation have access to separate revolving credit facilities with aggregate bank commitments of $1 billion and $1.95 billion, respectively. 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 2005 Annual Report on Form 10-K for further information.

Exelon’s, ComEd’s and PECO’s working capital, defined as current assets less current liabilities, are in net deficit positions primarily due to continued capital expenditures to improve and expand their service systems, current portions of debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust as well as maturing long-term debt at ComEd. ComEd intends to refinance the maturing long-term debt during 2006. As more fully described below, ComEd did not pay a dividend during the nine months ended September 30, 2006.

Cash Flows from Operating Activities

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. 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

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energy and its ability to continue to produce and supply power at competitive costs as well as collections from customers.

Cash flows from operations have been a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 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 will purchase electricity in the wholesale energy markets 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 beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be potential material adverse consequences to ComEd and, possibly, Exelon. ComEd has proposed a voluntary “cap and deferral” program to mitigate the impact on its residential customers of transitioning to the post rate freeze period. If approved as proposed and implemented, ComEd’s cash flows from operations would be reduced in the first years of the program, but would increase as any deferred amounts are collected with an appropriate return on any deferred balances. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion of ComEd’s procurement case.

The expiration of the PPA between Generation and ComEd on December 31, 2006 could negatively affect Generation’s cash flows from operations. In the event of rising power prices, Generation may be required to post increased collateral under contracts with new and existing counterparties, including ComEd (for which Generation has not been previously required to post collateral).

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. As discussed in Note 10 of the Combined Notes to Consolidated Financial Statements, this tax obligation is significant, and an adverse determination could require a significant payment.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 2006 and 2005:


	Nine Months
	Ended September 30,
	2006			2005			Variance

Net income	$	1,000		$	1,760		$	(760	)
Add (subtract):
Non-cash operating activities(a)		2,749			2,228			521
Income taxes		64			257			(193	)
Changes in working capital and other noncurrent assets and liabilities(b)		(259	)		(640	)		381
Pension and non-pension postretirement benefit contributions		(49	)		(2,059)			2,010

Net cash flows provided by operations	$	3,505		$	1,546		$	1,959


(a)		Represents depreciation, amortization and accretion, deferred income taxes, pension and non-pension postretirement benefit expense, equity in losses of unconsolidated affiliates, impairment charges 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.

The increase in cash flows from operations during the nine months ended September 30, 2006 compared to the same period in 2005 was primarily the result of $2 billion of discretionary contributions to Exelon’s pension plans, including contributions of $803 million, $109 million and $844 million by ComEd, PECO and Generation, respectively, during the first quarter of 2005, which was initially funded through a term loan agreement, as further described in the “Cash Flows from Financing Activities” section below. The Generation contribution was primarily funded by capital contributions from Exelon and included $2 million from internally generated funds.

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Cash flows provided by operations for the nine months ended September 30, 2006 and 2005 by registrant were as follows:


	Nine Months
	Ended September 30,
	2006		2005

Exelon	$	3,505	$	1,546
ComEd		741		37
PECO		806		591
Generation		1,888		826

Excluding the March 2005 discretionary pension contributions discussed above, changes in Exelon’s, ComEd’s, PECO’s and Generation’s cash flows from operations were generally consistent with changes in its results of operations, as adjusted by changes in working capital in the normal course of business.

In addition, significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2006 and 2005 were as follows:

ComEd


	•	At September 30, 2006 and December 31, 2005, ComEd had accrued payments to Generation under the PPA of $175 million and $242 million, respectively. At September 30, 2005 and December 31, 2004, ComEd had accrued payments to Generation under the PPA of $233 million and $189 million, respectively.

	•	During the third quarter of 2005, ComEd settled $325 million of interest rate swaps that were designated as cash flow hedges for a loss of $15 million which was paid in October 2005. This was recorded as a pre-tax charge to net income because the underlying transaction for which these interest rate swaps were entered into was no longer probable of occurring.

Generation


	•	During the nine months ended September 30, 2006 and 2005, Generation had net collections and net disbursements of counterparty collateral of $395 million and $99 million, respectively. The increase 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 January 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. Exelon expects to receive, in either the fourth quarter of 2006 or the first quarter of 2007, approximately $92 million related to this same deduction in connection with the filing of its 2005 tax return.

Cash Flows from Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2006 and 2005 by registrant were as follows:


	Nine Months
	Ended
	September 30,
	2006			2005

Exelon	$	(1,986	)	$	(1,685	)
ComEd		(670	)		(265	)
PECO		(220	)		(136	)
Generation		(1,000	)		(856	)

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Capital expenditures by registrant and business segment for the nine months ended September 30, 2006 and projected amounts for the twelve months ended 2006 are as follows:


	Nine Months
	Ended		Projected
	September 30, 2006		2006

ComEd	$	704	$	925
PECO		241		333
Generation		782		1,115
Other(a)		25		68

Total Exelon capital expenditures	$	1,752	$	2,441


(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.

ComEd and PECO. Approximately 50% of the projected 2006 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. Exelon is continuing to evaluate its total capital spending requirements. Exelon anticipates that ComEd’s and PECO’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities.

Generation. Generation’s capital expenditures for 2006 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.

Other significant investing activities of the Registrants for the nine months ended September 30, 2006 and 2005 were as follows:

Exelon


	•	Exelon contributed $73 million and $92 million to its investments in synthetic fuel-producing facilities during the nine months ended September 30, 2006 and 2005, respectively.

ComEd


	•	As a result of its prior contributions to the Exelon intercompany money pool, $308 million was returned to ComEd during the nine months ended September 30, 2005.

PECO


	•	As a result of its prior contributions to the Exelon intercompany money pool, $8 million and $34 million were returned to PECO during the nine months ended September 30, 2006 and 2005, respectively.

	•	During the nine months ended September 30, 2005, there was a net decrease in restricted cash that provided $27 million of cash.

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 acquired Reservoir Capital Group’s 50% interest in Sithe for cash payments of $97 million and sold 100% of Sithe to Dynegy, for net cash proceeds of $103 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Sithe.

134


	•	During the nine months ended September 30, 2005, Generation received approximately $52 million from Generation’s nuclear decommissioning trust funds for reimbursement of expenditures previously incurred for nuclear plant decommissioning activities related to retired units.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the nine months ended September 30, 2006 and 2005 by registrant were as follows:


	Nine Months
	Ended
	September 30,
	2006			2005

Exelon	$	(1,380	)	$	(207	)
ComEd		(71	)		236
PECO		(600	)		(504	)
Generation		(893	)		(199	)

Debt. 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 previously used to refinance amounts that ComEd used to repay $54 million of First Mortgage 9.875% Bonds, Series 75, due June 15, 2020, which ComEd redeemed in 2005; $163 million of First Mortgage 7.00% Bonds, Series 93, which matured July 1, 2005; and $107 million of 6.4% Notes which matured October 15, 2005. On August 28, 2006, ComEd issued $300 million aggregate principal amount of its First Mortgage 5.95% Bonds, Series 104, due August 15, 2016. The proceeds of the bonds were used to repay commercial paper and for other general corporate purposes. On October 2, 2006, ComEd reopened the First Mortgage 5.95% Bonds, Series 104, due August 15, 2016 and issued an additional $115 million. The proceeds of the bonds were used to pay $95 million of First Mortgage 8.25% Bonds, Series 76, due October 1, 2006 and $31 million of First Mortgage 8.375% Bonds, Series 78, due October 15, 2006 at maturity. On September 25, 2006, PECO issued $300 million of its First Mortgage Bonds 5.95% Series, due October 1, 2036. The proceeds were used to repay commercial paper and for other general corporate purposes.

On March 7, 2005, Exelon entered into a $2 billion term loan agreement. The loan proceeds were used to fund discretionary contributions of $2 billion to Exelon’s pension plans, including contributions of $803 million, $109 million and $842 million by ComEd, PECO and Generation, respectively. To facilitate the contributions by ComEd, PECO and Generation, Exelon contributed the corresponding amounts to the capital of each company. See Note 10 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report on Form 10-K for further information.

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.

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.

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Dividends. Cash dividend payments and distributions during the nine months ended September 30, 2006 and 2005 by registrant were as follows:


	Nine Months Ended
	September 30,
	2006		2005

Exelon	$	803	$	804
ComEd		—		352
PECO		371		350
Generation		444		749

Exelon paid dividends of $267 million, $268 million, and $268 million on March 10, 2006, June 12, 2006, and September 11, 2006, respectively, to shareholders of record at the close of business on February 15, 2006, May 15, 2006, and August 15, 2006, respectively. On July 25, 2006, Exelon’s board of directors declared a quarterly dividend of $0.40 per share on Exelon’s common stock, which is payable on December 11, 2006 to shareholders of record at the end of the day on November 15, 2006. See “Dividends” section of ITEM 5 of Exelon’s 2005 Annual Report on Form 10-K for a further discussion of Exelon’s dividend policy.

During the nine months ended September 30, 2006, ComEd did not pay a quarterly dividend. This decision by the ComEd Board of Directors not to declare a dividend 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 continue to assess ComEd’s ability to pay a dividend on a quarterly basis.

In 2003, Congress passed and President Bush signed into law the Jobs and Growth Tax Reconciliation Act, legislation which lowered the tax rate on capital gains and corporate dividends to 15% for most investors and to 5% for lower-income investors. Prior to enactment of this law, the maximum tax rate on dividend income was 38.6%. These provisions, which were originally scheduled to expire at the end of 2008, were extended to 2010 as part of the Tax Relief Reconciliation Act of 2005 passed in May 2006.

Intercompany Money Pool. During the nine months ended September 30, 2006, ComEd repaid $140 million that it had borrowed from the Exelon intercompany money pool. ComEd’s net borrowings from the Exelon intercompany money pool increased $110 million during the nine months ended September 30, 2005. PECO’s net borrowings from the Exelon intercompany money pool increased $7 million during the nine months ended September 30, 2005. Generation’s net borrowings from the Exelon intercompany money pool decreased $86 million and $283 million during the nine months ended September 30, 2006 and September 30, 2005, respectively.

Commercial Paper and Notes Payable. During the nine months ended September 30, 2006, Exelon, ComEd, PECO and Generation repaid $837 million, $306 million, $220 million and $311 million of commercial paper, respectively.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during the nine months ended September 30, 2006 and 2005 by registrant was as follows:


	Nine Months Ended September 30,
	2006		2005

Exelon	$	691	$	639
ComEd		261		278
PECO		430		361

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Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during the nine months ended September 30, 2006 and 2005 by registrant were as follows:


	Nine Months Ended September 30,
	2006		2005

ComEd	$	23	$	834
PECO		118		215
Generation		5		843

Other. Other significant financing activities for Exelon for the nine months ended September 30, 2006 and 2005 were as follows:


	•	Exelon purchased treasury shares totaling $54 million and $262 million during the nine months ended September 30, 2006 and 2005, respectively.

	•	Exelon received proceeds from employee stock plans of $149 million and $193 million during the nine months ended September 30, 2006 and 2005, respectively.

	•	There was $43 million and $0 of excess tax benefits included as a cash inflow in other financing activities during the nine months ended September 30, 2006 and 2005, respectively.

Credit Matters

Credit Facilities. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Registrants. The Registrants may use credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Notes 7 and 18 of the Combined Notes to Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

At September 30, 2006, 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(c)	$	200	$	200	$	—
ComEd		1,000		957		153
PECO(c)		500		500		—
Generation(c)		2,750		2,658		—


(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. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(c)		Exelon, PECO and Generation are parties to two credit agreements with aggregate bank commitments of $1.5 billion. The credit agreements contain separate sublimits for Exelon, PECO and Generation, which are reflected in the table, which sublimits may be changed upon written notification to the bank group. Generation is also party to bilateral credit agreements with various banks with aggregate bank commitments of $1.95 billion, which are reflected in the table above.

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, PECO and Generation, the maximum LIBOR adder is 170 basis points; and in the case of ComEd, it is 200 basis points.

The average interest rates on commercial paper for the nine months ended September 30, 2006 for Exelon, ComEd, PECO and Generation were approximately 5.00%, 5.03%, 4.96% and 4.94%, respectively.

137

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 following table summarizes the minimum thresholds reflected in the credit agreements for the nine-month period ended September 30, 2006:

Exelon

ComEd

PECO

Generation

Credit agreement threshold

2.65 to 1

2.25 to 1

3.25 to 1

At September 30, 2006, 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 September 30, 2006, 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. Maximum amounts contributed to and borrowed from the money pool by participant during the nine months ended September 30, 2006 are described in the following table in addition to the net contribution or borrowing as of September 30, 2006:


					September 30,
					2006
	Maximum		Maximum		Contributed
	Contributed		Borrowed		(Borrowed)

ComEd(a)	$	—	$	140	$	—
PECO		21		183		—
Generation		83		234		(6	)
BSC		234		134		6
UII, LLC		5		—		—
Exelon		248		N/A		—


(a)		As of January 10, 2006, ComEd suspended participation in the intercompany money pool. During the first quarter of 2006, ComEd repaid $140 million that it had borrowed from the intercompany money pool.

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 July 26, 2006, Moody’s Investors Service (Moody’s) downgraded the long-term and short-term debt ratings of ComEd. The rating action concludes Moody’s review for possible downgrade that commenced on December 15, 2005. Moody’s attributes the downgrade to a difficult political and regulatory environment in Illinois, uncertainty about the outcome of the electricity supply auction and the expectation of a material regulatory deferral. On October 10, 2006, Moody’s placed ComEd’s security ratings under review for possible downgrade resulting from perceived increasing political and regulatory risk in Illinois.

On July 31, 2006, Fitch Ratings downgraded the long-term ratings of ComEd. ComEd’s short-term rating was affirmed at F2. The rating outlook remains negative. The rating action reflects Fitch’s view of the unfavorable rate order issued by the ICC and of uncertainty in Illinois with respect to the electricity procurement process scheduled for implementation in January 2007.

The debt ratings and rating outlook for Exelon, Generation and PECO by Moody’s and Fitch Ratings are unchanged.

138

On October 5, 2006, S&P downgraded the short-term and long-term security ratings of ComEd due to perceived political risk related to the rate freeze extension proposal. S&P downgraded ComEd’s senior unsecured debt to BB+, which is below investment grade. The ratings on Exelon, PECO and Generation were affirmed. The ratings for all Registrants were placed under Credit Watch with negative implications.

The current security ratings for ComEd are shown in the table below:


		Fitch	Standard
	Moody’s	Ratings	& Poor’s

Senior secured debt	Baa2	BBB+	BBB
Senior unsecured debt	Baa3	BBB	BB+
Commercial paper	P-3	F2	A3

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.

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.

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to suspend synthetic fuel production was primarily driven by the level and volatility of oil prices. In addition, the proposed Federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. Due to the reduction in oil prices during the third quarter of 2006, the operators resumed production at their synthetic fuel-producing facilities in September 2006 and are expected to produce at full capacity through the remainder of 2006. As of September 30, 2006, Exelon has estimated the 2006 phase-out to be 44%, which has reduced Exelon’s after-tax credits of $96 million to $55 million for the nine months ended September 30, 2006. As of September 30, 2006, Exelon has estimated the 2007 phase-out of tax credits to be 39%. Exelon anticipates generating approximately $160 million of cash over the life of these investments. 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 represent commitments triggered by future events. The Registrants’ contractual obligations and commercial commitments as of September 30, 2006 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2005 Annual Report on Form 10-K except for the following:

Exelon


	•	Letters of credit increased $60 million and guarantees decreased $78 million, respectively, primarily as a result of Generation’s energy trading activities.

ComEd


	•	Letters of credit increased $16 million.

	•	ComEd issued $325 million First Mortgage 5.90% Bonds, Series 103, due March 15, 2036 and $300 million First Mortgage 5.95% Bonds, Series 104, due August 15, 2016.

139

PECO


	•	Guarantees decreased $9 million related to changes in surety bonds outstanding.

	•	PECO issued $300 million First Mortgage 5.95% Bonds Series, due October 1, 2036.

Generation


	•	Letters of credit increased $47 million and guarantees decreased $35 million, respectively, primarily as a result of Generation’s energy trading activities.

	•	Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $3.1 billion during the nine months ended September 30, 2006, reflecting increases of approximately $3.4 billion and $1.3 billion in 2007 and 2008 sales commitments, respectively, and other small increases in commitments in years beyond 2008, offset by the fulfillment of approximately $1.8 billion of 2006 commitments during the nine months ended September 30, 2006. The increases were primarily due to increased forward sales of energy to counterparties other than ComEd as a result of the pending 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 September 30, 2006 increased by $340 million for 2009 and 2010, and $277 million for 2011 and beyond, as compared to December 31, 2005 due to contracts entered into in the normal course of business.

	•	Pursuant to U.S. Environmental Protection Agency regulations that will impose limits on certain future emissions by generation stations, the co-owners of the Keystone generating station formally approved on June 30, 2006 a capital plan to install environmental controls at the station for which Exelon’s share, based on its 20.99% ownership interest, would be approximately $150 million over the life of the control project.

140

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 September 30, 2006 compared to three months ended September 30, 2005 and nine months ended September 30, 2006 compared to nine months ended September 30, 2005 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 commercial paper. ComEd’s access to external financing at reasonable terms may be significantly affected by developments in or related to the proceedings concerning its post-2006 rates and recovery of energy costs and will also be affected by its credit ratings and general business conditions, as well as that of the utility industry in general. See Note 5 of the Combined Notes to Consolidated Financial Statements for information regarding ComEd’s post-2006 rates and recovery of energy costs, including pending legislation to extend the current rate freeze. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to a revolving credit facility that ComEd 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 ComEd’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 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.

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.

141

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 September 30, 2006 compared to three months ended September 30, 2005 and nine months ended September 30, 2006 compared to nine months ended September 30, 2005 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 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.

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.

142

EXELON GENERATION COMPANY

General

Generation operates in a single business segment and its operations consist principally of the electric generating facilities, wholesale energy marketing operations, competitive retail sales and certain other generation projects.

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 September 30, 2006 compared to three months ended September 30, 2005 and nine months ended September 30, 2006 compared to nine months ended September 30, 2005 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 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.

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.

143


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 Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC 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 RMC reports to the Exelon Board of Directors on the scope of the derivative and risk management activities.

Commodity Price Risk (Exelon, ComEd and Generation)

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. Exelon’s primary source of commodity price risk is at Generation; however, ComEd also has some commodity price risk associated with certain wholesale contracts.

ComEd

ComEd has derivatives related to one wholesale contract and various other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. Additionally, the 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 purchase exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes. As of September 30, 2006, the fair value of the derivative wholesale contract of $5 million was recorded on ComEd’s Consolidated Balance Sheet, of which $4 million is classified as a current liability and $1 million is classified as a long-term liability. The financial derivative used to manage the market price exposure to several wholesale contracts is designated and effective as a cash flow hedge, as defined in SFAS No. 133. As such, changes in the fair value of the derivative are recorded in other comprehensive income (OCI) and gains and losses are recognized in earnings when the underlying transaction occurs. As of September 30, 2006, the fair value of this contract of $4 million was recorded on ComEd’s Consolidated Balance Sheet as a current liability.

Generation

Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts qualify for the normal purchases and normal sales exception to SFAS No. 133, which is discussed in Critical Accounting Policies and Estimates within Exelon’s 2005 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 fair value of qualifying hedge contracts 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 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. 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 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. The length of time over which cash flows related to energy commodities are

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currently being cash-flow hedged is in excess of three years. Generation currently has an estimated 94% hedge ratio for the remainder of 2006 for its energy marketing portfolio. This 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 load assumptions are based on forecasted average demand. The 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. Generation also has an estimated 86% hedge ratio for 2007 for its energy marketing portfolio. Absent any efforts to mitigate market price exposure, the estimated market price exposure for Generation’s unhedged non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity is approximately a $5 million after-tax decrease in net income for the remainder of 2006. This sensitivity assumes a 94% hedge ratio and 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.

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load obligations through 2006. At times, ComEd’s load obligations are greater than the capacity of Generation’s owned generating units in the ComEd region. As such, Generation procures power through purchase power and lease agreements and has contracted for access to additional generation through bilateral long-term PPAs. Following the expiration of the Illinois transition period and the end of the PPA between Generation and ComEd in 2006, all of Generation’s supply in the ComEd region will be available for sale into the wholesale markets and exposed to changes in market prices.

Proprietary Trading Activities. Generation began to use financial contracts for proprietary trading purposes in 2001. 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 are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall 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 nine months ended September 30, 2006 resulted in a gross margin gain of $14 million (before income taxes). 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 $120,000 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 nine months ended September 30, 2006 of $3,978 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 value-at-risk limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities.

Trading and Non-Trading Marketing Activities. The following detailed presentation of the trading and non-trading 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, 2006 to September 30, 2006. 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

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well as the settlements from 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 liabilities at January 1, 2006	$	(540	)
Total change in fair value during 2006 of contracts recorded in earnings		89
Reclassification to realized at settlement of contracts recorded in earnings		43
Reclassification to realized at settlement from OCI		178
Effective portion of changes in fair value — recorded in OCI		460

Total mark-to-market energy contract net assets at September 30, 2006	$	230

The following table details the balance sheet classification of Generation’s mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2006 and December 31, 2005:


	September 30,			December 31,
	2006			2005

Current assets	$	797		$	916
Noncurrent assets		335			286

Total mark-to-market energy contract assets		1,132			1,202

Current liabilities		(723	)		(1,282	)
Noncurrent liabilities		(179	)		(460	)

Total mark-to-market energy contract liabilities		(902	)		(1,742	)

Total mark-to-market energy contract net assets (liabilities)	$	230		$	(540	)

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 varies by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. 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 September 30, 2006 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 Exelon 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

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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
														2011 and		Total Fair
	2006			2007			2008			2009		2010		Beyond		Value

Normal Operations, qualifying cash-flow hedge contracts(a):
Actively quoted prices	$	1		$	2		$	—		$	—	$	—	$	—	$	3
Prices provided by other external sources		23			52			36			3		—		—		114

Total	$	24		$	54		$	36		$	3	$	—	$	—	$	117

Normal Operations, other derivative contracts (b):
Actively quoted prices	$	(36	)	$	(11	)	$	28		$	—	$	—	$	—	$	(19	)
Prices provided by other external sources		19			98			(5	)		—		—		—		112
Prices based on model or other valuation methods		1			18			1			—		—		—		20

Total	$	(16	)	$	105		$	24		$	—	$	—	$	—	$	113


(a)		Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in OCI.

(b)		Mark-to-market gains and losses on other non-trading and trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of September 30, 2006. 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, 2006 to September 30, 2006, 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
(In millions)	Hedging Activities			Hedges			Hedges

Accumulated OCI derivative loss at January 1, 2006	$	(314	)	$	(4	)	$	(318	)
Changes in fair value		277			2			279
Reclassifications from OCI to net income		107			—			107

Accumulated OCI derivative gain (loss) at September 30, 2006	$	70		$	(2	)	$	68

Credit Risk (Exelon, ComEd, PECO and Generation)

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 is currently unable to predict the impact of the power auction prices, effective in January 2007, on its provision for uncollectible accounts. ComEd will monitor nonpayment from customers and will make any

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necessary adjustments to the provision for uncollectible accounts. PECO has experienced an increase in its provision for uncollectible accounts in 2006 as compared to 2005 as a result of higher accounts receivable balances in 2006 resulting from increased revenues, changes in PAPUC-approved regulations which relaxed customer payment terms and an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in PAPUC regulations.

Under the Competition Act, licensed entities, including alternative electric 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.

Generation

Generation’s purchased power agreement (PPA) with ComEd expires at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren Corporation (Ameren) auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation will sell more electricity at market-based rates through supplier forward contracts with ComEd and Ameren and bilateral agreements with other new and existing counterparties. 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 is anticipated to change based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the proposed rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of electricity. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets. For additional information on the Illinois auction, the proposed legislation and the various regulatory proceedings, see Note 5 of the Combined Notes to Consolidated Financial Statements.

Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. 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 September 30, 2006. They further delineate that exposure by the 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

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risk by credit rating of the counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through 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 September 30, 2006(a)	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure

Investment grade	$	809	$	243	$	566		1	$	74
Non-investment grade		17		3		14		—		—
No external ratings
Internally rated — investment grade		11		1		10		—		—
Internally rated — non-investment grade		4		1		3		—		—

Total	$	841	$	248	$	593		1	$	74


(a)		This table does not include accounts receivable exposure and credit risk exposure from retail energy sales.


	Maturity of Credit Risk Exposure
					Exposure		Total Exposure
	Less than				Greater than		Before Credit
Rating as of September 30, 2006(a)	2 Years		2-5 Years		5 Years		Collateral

Investment grade	$	729	$	80	$	—	$	809
Non-investment grade		17		—		—		17
No external ratings
Internally rated — investment grade		11		—		—		11
Internally rated — non-investment grade		4		—		—		4

Total	$	761	$	80	$	—	$	841


(a)		This table does not include accounts receivable exposure and credit risk exposure from retail energy sales.

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.

Generation sells output through bilateral contracts. Generation’s sales to counterparties other than ComEd and PECO will increase due to the expiration of the PPA with ComEd at the end of 2006. 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. Under the Illinois Auction Rules and the supplier forward contracts that Generation will enter into with ComEd and Ameren, beginning in 2007, collateral postings between ComEd and Generation will be one-sided. That is, if market prices fall below ComEd’s or Ameren’s

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contracted price levels, ComEd or Ameren are not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation is required to post collateral.

ISOs. Generation participates in the following established, real-time energy markets that are administered by ISOs: PJM, ISO New England, New York ISO, Midwest ISO, 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 ISOs. 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 the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the 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.

Exelon

Exelon’s Consolidated Balance Sheet as of September 30, 2006 included a $524 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 $968 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, ComEd, PECO and Generation)

Variable Rate Debt. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants 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 September 30, 2006, the Registrants did not have any fair-value or cash-flow interest-rate 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 September 30, 2006. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a decrease in pre-tax earnings for the three months ended September 30, 2006 of less than $1 million for ComEd, PECO and Generation.

Equity Price Risk (Exelon and Generation)

Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of September 30, 2006, 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 $430 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Policies and Estimates section within Exelon’s 2005 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 third quarter of 2006, each registrant’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 each registrant 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 September 30, 2006, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant 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 third quarter of 2006 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting. PECO is anticipated to complete the Common Customer System project, which will move the PECO customer accounts onto the existing ComEd customer information management system (CIMS) to provide a common billing system for Exelon. This implementation is occurring during the fourth quarter of 2006, which may impact various processes and controls. In connection with the implementation of CIMS, PECO will implement new processes and modify existing processes in an effort to improve its internal controls and streamline processes.

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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’ 2005 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 September 30, 2006, the Registrants’ risk factors changed compared to the risk factors described in Exelon’s 2005 Annual Report on Form 10-K as follows: (a) the risk factors under the heading “Proposed Merger with PSEG” are no longer applicable as Exelon gave PSEG formal notice of termination of the Merger Agreement on September 14, 2006 (see Note 4 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Merger termination) and (b) the Registrants identified the additional risk factors described below.

ComEd may file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code if proposed rate freeze legislation is enacted into law.

As more fully described in Note 5 of the Combined Notes to Consolidated Financial Statements, ComEd is scheduled to begin billing customers under ICC-approved rates in January 2007, which reflect the pricing in supplier forward contracts entered into as a result of a reverse-auction competitive bidding process for ComEd’s procurement of electricity. Various governmental and consumer groups have opposed the increased rates that are a byproduct of this auction, and legislation has been introduced that, if enacted, would provide for a rate freeze extension. If the currently proposed rate freeze legislation is enacted into law, ComEd would have contractual obligations to purchase electricity under the supplier forward contracts at prices higher than the rates it would be allowed to collect from its customers for electricity. It is currently estimated that ComEd could incur operating losses of approximately $1.4 billion ($850 million after taxes) or more, depending on various factors, if the current rate freeze is extended through 2007. Also, ComEd’s ability to obtain new financing or the ability to re-finance its approximately $500 million of maturing debt instruments in 2007, will be severely limited due to expected shortfalls in cash flow, anticipated further credit downgrades to below investment grade and the threat of a bankruptcy filing. ComEd’s projected cash shortfall under a rate freeze extension is anticipated to be approximately $1.4 billion or more in 2007. If the legislation is passed and allowed to take effect, the associated negative financial implications could lead ComEd to file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

Exelon Corporation and Generation will be negatively affected if ComEd files for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

Exelon anticipates that a bankruptcy filing by ComEd would have significant adverse consequences for Exelon and Generation. These adverse consequences may include, but are not limited to: a significant loss in value of Exelon’s investment in ComEd; possible dilution of Exelon’s ownership interest in ComEd; possible reductions in credit ratings which could increase borrowing costs; uncertainty in collection of receivables from ComEd for services provided by Exelon Business Services Company; uncertainty in the enforcement of Generation’s rights under its supplier forward contracts with ComEd and possible rejection of the supplier forward contracts in a ComEd bankruptcy; incurring significant legal and other costs associated with the bankruptcy filing; possible negative income tax consequences; challenges in retaining employees due to the bankruptcy; and possible reduced ability to effectively administer and allocate the costs of the various Exelon-sponsored benefit plans. These items, along with other possible negative effects of a ComEd bankruptcy, could have a material adverse effect on Exelon’s and Generation’s results of operations, financial position and cash flows.

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Absent replacement hedges, Generation will be exposed to increased market risk and price volatility after the expiration of significant purchase power arrangements after 2006.

Generation currently sells a majority of its output to ComEd and PECO under long-term PPAs. Beginning January 1, 2007, Generation will provide power to ComEd and Ameren under supplier forward contracts, in compliance with the ICC-approved reverse power procurement auction. For additional information on the ComEd and Ameren auctions, see Note 5 of the Combined Notes to Consolidated Financial Statements. As a result of the pending expiration of the PPA between Generation and ComEd at the end of 2006, Generation will be exposed to increased commodity price risk associated with the electricity historically sold to serve ComEd’s load obligations that will now be sold at market-based prices and will continue to be exposed to fluctuations in commodity prices for electricity after 2006 for the unhedged portion of its electricity trading portfolio. This increase in risk is partially mitigated by the reduction of risks attributable to peaking costs associated with the prior load obligations under the ComEd PPA that expires at the end of 2006. For 2007, Generation has hedges in place that result in a Midwest risk profile similar to previous years. Generation has been and will continue to be proactive in looking for hedging strategies to mitigate this risk as well.

Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations.

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or energy will not perform their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell power in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to the risks of whatever default mechanisms exist in that market, some of which attempt to spread the risk across all participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.

Generation’s PPA with ComEd expires at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation will sell more electricity at market-based rates through supplier forward contracts with ComEd and Ameren and bilateral agreements with other new and existing counterparties. 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 is anticipated to change based on the creditworthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the proposed rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of electricity. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets. For additional information on the ComEd auction and the various regulatory proceedings and possible legislative actions, see Note 5 of the Combined Notes to Consolidated Financial Statements.

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Registrants operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal and are an important aspect of their operations. Violations of these emission and disposal requirements can subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs and operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages. In addition, the Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous

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substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies will be one component of such costs. Also, 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.

In addition, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.

In some cases, a third party who has acquired assets from a Registrant has assumed liability the Registrant may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee may be limited by the financial resources of the transferee.

For additional information regarding environmental matters, including nuclear generating station groundwater, see Note 13 of the Combined Notes to Consolidated Financial Statements.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

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

July 1 — July 31, 2006

1,499

56.83

—

)

August 1 — August 31, 2006

426

58.73

—

)

September 1 — September 30, 2006

1,294

60.53

)

Total

3,219

58.57

—

)


(a)		Shares other than those purchased as part of a publicly announced plan primarily represent restricted 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 (ESPP). 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 ESPP. 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 5.	Other Information

ComEd

On August 1, 2006, ComEd set a new record for highest daily peak load experienced to date of 23,613 megawatts.

PECO

On August 3, 2006, PECO set a new record for highest daily peak load experienced to date of 8,932 megawatts.

154


Item 6.	Exhibits


4-1-1	Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:
	Dated as of	File Reference	Exhibit No.
	September 15, 2006	000-16844, Form 8-K dated September 25, 2006	4.1
4-3-1	Supplemental Indentures to Commonwealth Edison Mortgage:
	Dated as of	File Reference	Exhibit No.
	August 1, 2006	1-1839, Form 8-K dated August 28, 2006	4.1
	September 15, 2006	1-1839, Form 8-K dated October 2, 2006)	4.1


Exhibit
No.		Description

	10-1	Bilateral Credit Facility dated as of September 19, 2006 between Exelon Generation Company, LLC and JP Morgan Chase Bank, N.A. (File No. 333-85496, Form 8-K dated September 19, 2006, Exhibit 99.1)
	10-2	Bilateral Credit Facility dated as of September 19, 2006 between Exelon Generation Company, LLC and Barclays Bank PLC (File No. 333-85496, Form 8-K dated September 19, 2006, Exhibit 99.2)
	10-3	Bilateral Credit Facility dated as of September 19, 2006 between Exelon Generation Company, LLC and Wachovia Bank, N.A. (File No. 333-85496, Form 8-K dated September 19, 2006, Exhibit 99.3)
	10-4	One Hundred and Second Supplemental Indenture, dated as of September 15, 2006, to the First and Refunding Mortgage, dated as of May 1, 1923, between PECO Energy Company and Wachovia Bank, National Association, as trustee. (File No. 000-16844, Form 8-K dated September 25, 2006, Exhibit 4.1)
	10-5	Supplemental Indenture dated as of August 1, 2006 from ComEd to BNY Midwest Trust Company, as trustee, and D.G. Donovan, as co-trustee. (File No. 1-1839, Form 8-K dated August 28, 2006, Exhibit 4.1)
	10-6	Supplemental Indenture dated as of September 15, 2006 from ComEd to BNY Midwest Trust Company, as trustee, and D.G. Donovan, as co-trustee. (File No. 1-1839, Form 8-K dated October 2, 2006, Exhibit 4.1)
	10-7	Credit Agreement dated as of October 26, 2006 between Exelon Corporation and Various Financial Institutions (File No. 1-16169, Form 8-K dated October 26, 2006, Exhibit 99.1)
	10-8	Credit Agreement dated as of October 26, 2006 between Exelon Generation Company and Various Financial Institutions (File No. 333-85496, Form 8-K dated October 26, 2006, Exhibit 99.2)
	10-9	Credit Agreement dated as of October 26, 2006 between PECO Energy Company and Various Financial Institutions (File No. 000-16844, Form 8-K dated October 26, 2006, Exhibit 99.3)

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 September 30, 2006 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 Frank M. Clark for Commonwealth Edison Company
31-4	—	Filed by Robert K. McDonald for Commonwealth Edison Company
31-5	—	Filed by John L. Skolds for PECO Energy Company
31-6	—	Filed by John F. Young for PECO Energy Company
31-7	—	Filed by John L. Skolds for Exelon Generation Company, LLC
31-8	—	Filed by John F. Young for Exelon Generation Company, LLC

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 September 30, 2006 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 Frank M. Clark for Commonwealth Edison Company

155

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)

October 27, 2006

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 F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

October 27, 2006

157

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 F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

October 27, 2006

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 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)

October 27, 2006

158


		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
	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
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income (Loss)		10
	Consolidated Statements of Cash Flows		11
	Consolidated Balance Sheets		12
	Consolidated Statement of Changes in Shareholders’ Equity		14
	PECO Energy Company
	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
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income		20
	Consolidated Statements of Cash Flows		21
	Consolidated Balance Sheets		22
	Consolidated Statement of Changes in Member’s Equity		24
	Combined Notes to Consolidated Financial Statements		25
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		88
	Exelon Corporation		88
	Commonwealth Edison Company		141
	PECO Energy Company		142
	Exelon Generation Company, LLC		143
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		144
ITEM 4.	CONTROLS AND PROCEDURES		151

PART II.	OTHER INFORMATION		152
ITEM 1.	LEGAL PROCEEDINGS		152
ITEM 1A.	RISK FACTORS		152
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		154
ITEM 5.	OTHER INFORMATION		154
ITEM 6.	EXHIBITS		155


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

Balance, December 31, 2005	$	1,588	$	4,890		$	(1,180	)	$	1,099	$	(1	)	$	6,396
Net loss		—		—			(325	)		—		—			(325	)
Allocation of tax benefit from parent		—		17			—			—		—			17
Appropriation of Retained Earnings for future dividends		—		—			(340	)		340		—			—
Resolution of certain tax matters		—		(5	)		—			—		—			(5	)
Other comprehensive loss, net of income taxes of $0		—		—			—			—		(1	)		(1	)

Balance, September 30, 2006	$	1,588	$	4,902		$	(1,845	)	$	1,439	$	(2	)	$	6,082


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

Balance, December 31, 2005	$	2,193	$	87	$	(1,232	)	$	649		$	7		$	1,704
Net income		—		—		—			320			—			320
Common stock dividends		—		—		—			(368	)		—			(368	)
Preferred stock dividends		—		—		—			(3	)		—			(3	)
Repayment of receivable from parent		—		—		106			—			—			106
Allocation of tax benefit from parent		30		—		—			—			—			30
Other comprehensive loss, net of income taxes of $(2)		—		—		—			—			(1	)		(1	)

Balance, September 30, 2006	$	2,223	$	87	$	(1,126	)	$	598		$	6		$	1,788


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


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


(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.

(e)		See Note 5 — Regulatory Issues for further discussion of the loss on extinguishment of long-term debt. Recovery of these costs was granted in the July 26, 2006 ICC rate order.

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


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


(e)		ComEd has a payable to Exelon under the Tax Sharing Agreement which is partially offset by a receivable from Exelon for the allocation of tax benefits. The December 31, 2005 receivable from Exelon for the allocation of tax benefits was settled in 2006. See Note 10 — Income Taxes for additional information.

(f)		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. See Note 11 of ComEd’s Notes to Consolidated Financial Statements within ComEd’s 2005 Annual Report on Form 10-K for additional information.

(g)		ComEd has a short-term payable to Generation, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation.


(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 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. See Note 9 of PECO’s Notes to Consolidated Financial Statements within PECO’s 2005 Annual Report on Form 10-K for additional information.

(h)		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 2006 through 2010.


32-4	—	Filed by Robert K. McDonald for Commonwealth Edison Company
32-5	—	Filed by John L. Skolds for PECO Energy Company
32-6	—	Filed by John F. Young for PECO Energy Company
32-7	—	Filed by John L. Skolds for Exelon Generation Company, LLC
32-8	—	Filed by John F. Young for Exelon Generation Company, LLC