UNITED STATES SECURITIES AND EXCHANGE COMMISSION

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, 2004
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) 10 South Dearborn Street – 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321			36-0938600
	1-1401			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, 2004 was:

Exelon Corporation Common Stock, without par value		662,549,435
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,488
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 an accelerated filer (as defined in Rule 12b-2 of the Act). Exelon Corporation     Yes þ          No o     Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC     Yes o          No þ.

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TABLE OF CONTENTS

				Page No.
FILING FORMAT					3
FORWARD-LOOKING STATEMENTS					3
WHERE TO FIND MORE INFORMATION					3
PART I.		FINANCIAL INFORMATION			5
Item 1.		Financial Statements			5
		Exelon Corporation
		Consolidated Statements of Income and Comprehensive Income			6
		Consolidated Statements of Cash Flows			7
		Consolidated Balance Sheets			8
		Commonwealth Edison Company
		Consolidated Statements of Income and Comprehensive Income			10
		Consolidated Statements of Cash Flows			11
		Consolidated Balance Sheets			12
		PECO Energy Company
		Consolidated Statements of Income and Comprehensive Income			14
		Consolidated Statements of Cash Flows			15
		Consolidated Balance Sheets			16
		Exelon Generation Company, LLC
		Consolidated Statements of Income and Comprehensive Income			18
		Consolidated Statements of Cash Flows			19
		Consolidated Balance Sheets			20
		Combined Notes to Consolidated Financial Statements			22
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			77
		Exelon Corporation			78
		Commonwealth Edison Company			117
		PECO Energy Company			134
		Exelon Generation Company, LLC			148
Item 3.		Quantitative and Qualitative Disclosure About Market Risk			163
Item 4.		Controls and Procedures			171
PART II.		OTHER INFORMATION			172
Item 1.		Legal Proceedings			172
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			172
		Exelon Corporation			172
Item 5.		Other Information			173
		Commonwealth Edison Company			173
		PECO Energy Company			173
		Generation Company, LLC			173
Item 6.		Exhibits			174

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				Page No.
SIGNATURES					178
		Exelon Corporation			178
		Commonwealth Edison Company			178
		PECO Energy Company			179
		Exelon Generation Company, LLC			179
CERTIFICATION EXHIBITS					180

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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 those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2004 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2004 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 19, ComEd — Note 15, PECO — Note 14 and Generation — Note 13 and (c) other factors discussed in 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 450 Fifth Street, N.W., 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 web site maintained by the SEC at www.sec.gov and Exelon’s website at www.exeloncorp.com.

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PART I. FINANCIAL INFORMATION

Item 1.     Financial Statements

5

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EXELON CORPORATION

				Three Months								Nine Months
				Ended								Ended
				September 30,								September 30,
(In millions, except per share data)				2004				2003				2004				2003
Operating revenues				$	3,865			$	4,441			$	11,137			$	12,236
Operating expenses
	Purchased power				873				1,179				2,107				2,765
	Purchased power from AmerGen Energy Company, LLC				—				133				—				310
	Fuel				407				551				1,781				1,908
	Impairment of Boston Generating, LLC long-lived assets				—				945				—				945
	Operating and maintenance				815				1,203				2,921				3,362
	Depreciation and amortization				364				293				980				842
	Taxes other than income				178				131				556				489
		Total operating expenses			2,637				4,435				8,345				10,621
Operating income					1,228				6				2,792				1,615
Other income and deductions
	Interest expense				(132	)			(213	)			(418	)			(652	)
	Interest expense to affiliates				(88	)			(4	)			(271	)			(9	)
	Distributions on preferred securities of subsidiaries				(1	)			(8	)			(3	)			(30	)
	Equity in earnings (losses) of unconsolidated affiliates				(42	)			49				(97	)			82
	Other, net				(107	)			(44	)			121				(226	)
		Total other income and deductions			(370	)			(220	)			(668	)			(835	)
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles					858				(214	)			2,124				780
Income taxes					280				(112	)			656				258
Income (loss) before minority interest and cumulative effect of changes in accounting principles					578				(102	)			1,468				522
Minority interest					(1	)			—				10				(3	)
Income (loss) before cumulative effect of changes in accounting principles					577				(102	)			1,478				519
Cumulative effect of changes in accounting principles (net of income taxes of $(5) for the three months ended September 30, 2004 and $17 and $69 for the nine months ended September 30, 2004 and 2003, respectively)					(9	)			—				23				112
Net income (loss)					568				(102	)			1,501				631
Other comprehensive income (loss), net of income taxes
	Minimum pension liability				—				9				—				9
	Change in net unrealized gain (loss) on cash-flow hedges				77				142				(68	)			58
	Foreign currency translation adjustment				—				—				(4	)			2
	Unrealized gain on marketable securities				7				5				18				3
	SFAS No. 143 transition adjustment				—				—				—				168
	Interest in other comprehensive income of unconsolidated affiliates				—				1				2				9
		Total other comprehensive income (loss)			84				157				(52	)			249
Total comprehensive income				$	652			$	55			$	1,449			$	880
Average shares of common stock outstanding — Basic					661				652				660				650
Average shares of common stock outstanding — Diluted					669				652				668				655
Earnings (loss) per average common share — Basic:
	Income (loss) before cumulative effect of changes in accounting principles			$	0.87			$	(0.16	)		$	2.23			$	0.80
	Cumulative effect of changes in accounting principles				(0.01	)			—				0.04				.17
	Net income (loss)			$	0.86			$	(0.16	)		$	2.27			$	0.97
Earnings (loss) per average common share — Diluted:
		Income (loss) before cumulative effect of changes in accounting principles		$	0.86			$	(0.16	)		$	2.21			$	0.79
	Cumulative effect of changes in accounting principles				(0.01	)			—				0.04				0.17
	Net income (loss)			$	0.85			$	(0.16	)		$	2.25			$	0.96
Dividends per common share				$	0.31			$	0.25			$	0.86			$	0.71

See Combined Notes to Consolidated Financial Statements

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

					Nine Months
					Ended
					September 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	1,501			$	631
	Adjustments to reconcile net income to net cash flows provided by operating activities:
		Depreciation, amortization and accretion, including nuclear fuel				1,507				1,290
		Cumulative effect of changes in accounting principles (net of income taxes)				(23	)			(112	)
		Impairment of investments				10				295
		Impairment of goodwill and other long-lived assets				1				950
		Deferred income taxes and amortization of investment tax credits				314				(363	)
		Provision for uncollectible accounts				59				72
		Equity in losses (earnings) of unconsolidated affiliates				97				(82	)
		Gains on sales of investments and wholly owned subsidiaries				(154	)			—
		Net realized gains on nuclear decommissioning trust funds				(2	)			(9	)
		Other operating activities				(35	)			62
		Changes in assets and liabilities:
			Receivables			245				24
			Inventories			(20	)			(55	)
			Other current assets			82				(93	)
			Accounts payable, accrued expenses and other current liabilities			(165	)			113
			Changes in receivables and payables to unconsolidated affiliates			(6	)			18
			Net realized and unrealized mark-to-market and hedging transactions			(5	)			2
			Pension and non-pension postretirement benefits obligations			(259	)			(161	)
			Other noncurrent assets and liabilities			7				(29	)
Net cash flows provided by operating activities						3,154				2,553
Cash flows from investing activities
	Capital expenditures					(1,295	)			(1,501	)
	Proceeds from liquidated damages					—				92
	Proceeds from nuclear decommissioning trust fund sales					1,422				1,880
	Investment in nuclear decommissioning trust funds					(1,624	)			(2,043	)
	Note receivable from unconsolidated affiliate					—				35
	Collection of other notes receivable					58				—
	Proceeds from sales of investments and wholly owned subsidiaries					238				186
	Proceeds from sales of long-lived assets					50				5
	Investment in synthetic fuel-producing facilities					(48	)			—
	Change in restricted cash					11				78
	Net cash increase from consolidation of Sithe Energies, Inc.					19				—
	Other investing activities					(9	)			45
Net cash flows used in investing activities						(1,178	)			(1,223	)
Cash flows from financing activities
	Issuance of long-term debt					75				2,105
	Retirement of long-term debt					(973	)			(2,075	)
	Issuance of long-term debt to financing affiliate					—				103
	Retirement of long-term debt to financing affiliates					(547	)			—
	Change in short-term debt					(1	)			(599	)
	Issuance of mandatorily redeemable preferred securities					—				200
	Retirement of mandatorily redeemable preferred securities					—				(250	)
	Retirement of preferred stock of subsidiaries					—				(50	)
	Payment on acquisition note payable to Sithe Energies, Inc.					(27	)			(210	)
	Dividends paid on common stock					(565	)			(461	)
	Proceeds from employee stock plans					192				139
	Purchase of treasury stock					(75	)			—
	Other financing activities					36				(85	)
Net cash flows used in financing activities						(1,885	)			(1,183	)
Increase in cash and cash equivalents						91				147
Cash and cash equivalents at beginning of period						493				469
Cash and cash equivalents, including cash classified as held for sale						584				616
Cash classified as held for sale on the consolidated balance sheet						—				(12	)
Cash and cash equivalents at end of period					$	584			$	604
Supplemental cash flow information
Noncash investing and financing activities:
	Consolidation of Sithe Energies, Inc. pursuant to FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities”				$	85			$	—
	Adoption of SFAS No. 143 — Adjustment to other paid in capital					—				210
	Note payable issued for investment in synthetic fuel-producing facilities					22				—

See Combined Notes to Consolidated Financial Statements

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	584			$	493
	Restricted cash and investments				166				97
	Accounts receivable, net
		Customer			1,613				1,567
		Other			414				676
	Mark-to-market derivative assets				403				337
	Inventories, at average cost
		Fossil fuel			191				212
		Materials and supplies			326				310
	Notes receivable from affiliate				—				92
	Deferred income taxes				49				122
	Assets held for sale				—				242
	Other				308				413
		Total current assets			4,054				4,561
Property, plant and equipment, net					20,724				20,630
Deferred debits and other assets
	Regulatory assets				4,931				5,226
	Nuclear decommissioning trust funds				4,943				4,721
	Investments				895				955
	Goodwill				4,707				4,719
	Mark-to-market derivative assets				432				133
	Other				1,373				991
		Total deferred debits and other assets			17,281				16,745
Total assets				$	42,059			$	41,936

See Combined Notes to Consolidated Financial Statements

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Commercial paper			$	325			$	326
	Note payable to Sithe Energies, Inc.				—				90
	Long-term debt due within one year				410				1,385
	Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year				581				470
	Accounts payable				1,136				1,238
	Mark-to-market derivative liabilities				655				584
	Accrued expenses				1,097				1,260
	Liabilities held for sale				—				61
	Other				301				306
		Total current liabilities			4,505				5,720
Long-term debt					7,814				7,889
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust					4,397				5,055
Long-term debt to other financing trusts					545				545
Deferred credits and other liabilities
	Deferred income taxes				4,735				4,320
	Unamortized investment tax credits				278				288
	Asset retirement obligation				3,473				2,997
	Pension obligations				1,344				1,668
	Non-pension postretirement benefits obligations				1,119				1,053
	Spent nuclear fuel obligation				875				867
	Regulatory liabilities				2,009				1,891
	Mark-to-market derivative liabilities				391				141
	Other				888				912
		Total deferred credits and other liabilities			15,112				14,137
		Total liabilities			32,373				33,346
Commitments and contingencies
Minority interest of consolidated subsidiaries					53				—
Preferred securities of subsidiaries					87				87
Shareholders’ equity
	Common stock				7,532				7,292
	Treasury stock, at cost				(75	)			—
	Retained earnings				3,256				2,320
	Accumulated other comprehensive loss				(1,167	)			(1,109	)
		Total shareholders’ equity			9,546				8,503
Total liabilities and shareholders’ equity				$	42,059			$	41,936

See Combined Notes to Consolidated Financial Statements

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COMMONWEALTH EDISON COMPANY

				Three Months								Nine Months
				Ended								Ended
				September 30,								September 30,
				2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues			$	1,720			$	1,717			$	4,441			$	4,473
	Operating revenues from affiliates				—				20				17				49
		Total operating revenues			1,720				1,737				4,458				4,522
Operating expenses
	Purchased power				80				6				144				17
	Purchased power from affiliate				827				885				1,870				1,984
	Operating and maintenance				185				261				533				691
	Operating and maintenance from affiliates				46				38				136				90
	Depreciation and amortization				104				97				309				287
	Taxes other than income				68				87				219				235
		Total operating expenses			1,310				1,374				3,211				3,304
Operating income					410				363				1,247				1,218
Other income and deductions
	Interest expense				(59	)			(107	)			(203	)			(322	)
	Interest expense to affiliates				(27	)			—				(85	)			—
	Distributions on mandatorily redeemable preferred securities				—				(6	)			—				(20	)
	Equity in (losses) of unconsolidated affiliates				(4	)			—				(13	)			—
	Interest income from affiliates				6				6				16				20
	Net loss on extinguishment of long-term debt				(106	)			—				(106	)			—
	Other, net				(1	)			9				6				28
		Total other income and deductions			(191	)			(98	)			(385	)			(294	)
Income before income taxes and cumulative effect of a change in accounting principle					219				265				862				924
Income taxes					95				102				351				365
Income before cumulative effect of a change in accounting principle					124				163				511				559
Cumulative effect of a change in accounting principle (net of income taxes of $0)					—				—				—				5
Net income					124				163				511				564
Other comprehensive income (loss), net of income taxes
	Change in net unrealized gain (loss) on cash-flow hedges				—				3				—				31
	Unrealized gain on marketable securities				—				2				—				3
	Foreign currency translation adjustment				(1	)			—				(1	)			2
		Total other comprehensive income (loss)			(1	)			5				(1	)			36
Total comprehensive income				$	123			$	168			$	510			$	600

See Combined Notes to Consolidated Financial Statements

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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

					Nine Months Ended
					September 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	511			$	564
	Adjustments to reconcile net income to net cash flows provided by operating activities:
		Depreciation and amortization				309				287
		Cumulative effect of a change in accounting principle (net of income taxes)				—				(5	)
		Deferred income taxes and amortization of investment tax credits				157				92
		Provision for uncollectible accounts				25				31
		Equity in losses of unconsolidated affiliates				13				—
		Other operating activities				80				46
		Changes in assets and liabilities:
			Receivables			(101	)			(55	)
			Inventories			(5	)			7
			Accounts payable, accrued expenses and other current liabilities			10				(44	)
			Receivables and payables to affiliates			24				(151	)
			Other current assets			5				(12	)
			Pension and non-pension postretirement benefits obligations			(141	)			(110	)
			Other noncurrent assets and liabilities			(20	)			(14	)
Net cash flows provided by operating activities						867				636
Cash flows from investing activities
	Capital expenditures					(518	)			(537	)
	Changes in Exelon intercompany money pool investment					405				(147	)
	Change in restricted cash					20				(17	)
	Notes receivable from affiliates					436				213
	Other investing activities					12				21
Net cash flows provided by (used in) investing activities						355				(467	)
Cash flows from financing activities
	Issuance of long-term debt					—				1,427
	Retirement of long-term debt					(798	)			(1,139	)
	Retirement of long-term debt to ComEd Transitional Funding Trust					(261	)			—
	Issuance of mandatorily redeemable preferred securities					—				200
	Retirement of mandatorily redeemable preferred securities					—				(200	)
	Changes in Exelon intercompany money pool borrowings					17				—
	Change in short-term debt					—				(71	)
	Dividends paid on common stock					(320	)			(305	)
	Contributions from parent					94				106
	Settlement of cash-flow and fair-value hedges					26				(45	)
	Other financing activities					2				(36	)
Net cash flows used in financing activities						(1,240	)			(63	)
(Decrease) increase in cash and cash equivalents						(18	)			106
Cash and cash equivalents at beginning of period						34				16
Cash and cash equivalents at end of period					$	16			$	122
Supplemental cash flow information
Noncash investing and financing activities:
	Adoption of SFAS No. 143 — adjustment to other paid in capital and goodwill				$	—			$	210

See Combined Notes to Consolidated Financial Statements

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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	16			$	34
	Restricted cash				—				20
	Accounts receivable, net
		Customer			784				683
		Other			43				68
	Inventories, at average cost				49				43
	Deferred income taxes				—				6
	Receivables from affiliates				19				23
	Investment in Exelon intercompany money pool				—				405
	Other				26				31
		Total current assets			937				1,313
Property, plant and equipment, net					9,349				9,096
Deferred debits and other assets
	Investments				36				36
	Investment in affiliates				59				73
	Goodwill				4,707				4,719
	Receivables from affiliates				1,906				2,271
	Pension asset				172				4
	Other				383				453
		Total deferred debits and other assets			7,263				7,556
Total assets				$	17,549			$	17,965

See Combined Notes to Consolidated Financial Statements

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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Long-term debt due within one year			$	284			$	236
	Long-term debt to ComEd Transitional Funding Trust due within one year				309				317
	Accounts payable				157				170
	Accrued expenses				529				540
	Payables to affiliates				222				207
	Payable to Exelon intercompany money pool				17				—
	Customer deposits				86				78
	Deferred income taxes				27				—
	Other				18				9
		Total current liabilities			1,649				1,557
Long-term debt					3,327				4,167
Long-term debt to ComEd Transitional Funding Trust					1,106				1,359
Long-term debt to other affiliates					361				361
Deferred credits and other liabilities
	Deferred income taxes				1,882				1,686
	Unamortized investment tax credits				46				48
	Non-pension postretirement benefits obligation				217				190
	Payables to affiliates				28				28
	Regulatory liabilities				2,009				1,891
	Other				297				336
		Total deferred credits and other liabilities			4,479				4,179
		Total liabilities			10,922				11,623
Commitments and contingencies
Shareholders’ equity
	Common stock				1,588				1,588
	Preference stock				7				7
	Other paid in capital				4,115				4,115
	Receivable from parent				(156	)			(250	)
	Retained earnings				1,075				883
	Accumulated other comprehensive income (loss)				(2	)			(1	)
		Total shareholders’ equity			6,627				6,342
Total liabilities and shareholders’ equity				$	17,549			$	17,965

See Combined Notes to Consolidated Financial Statements

13

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PECO ENERGY COMPANY

					Three Months								Nine Months
					Ended								Ended
					September 30,								September 30,
					2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues				$	1,119			$	1,146			$	3,381			$	3,319
	Operating revenues from affiliates					5				3				14				9
			Total operating revenues			1,124				1,149				3,395				3,328
Operating expenses
	Purchased power					49				61				149				189
	Purchased power from affiliate					409				421				1,108				1,101
	Fuel					28				28				354				285
	Fuel from affiliate					7				—				14				—
	Operating and maintenance					96				178				310				414
	Operating and maintenance from affiliates					26				14				77				39
	Depreciation and amortization					144				134				395				370
	Taxes other than income					64				12				181				123
			Total operating expenses			823				848				2,588				2,521
Operating income						301				301				807				807
Other income and deductions
	Interest expense					(15	)			(73	)			(42	)			(241	)
	Interest expense to affiliates					(61	)			(2	)			(187	)			(2	)
	Distributions on mandatorily redeemable preferred securities					—				(1	)			—				(6	)
	Equity in losses of unconsolidated affiliates					(6	)			—				(19	)			—
	Other, net					3				(10	)			8				—
			Total other income and deductions			(79	)			(86	)			(240	)			(249	)
Income before income taxes						222				215				567				558
Income taxes						83				74				195				193
Net income						139				141				372				365
Preferred stock dividends						(1	)			(1	)			(3	)			(4	)
Net income on common stock					$	138			$	140			$	369			$	361
Other comprehensive income, net of income taxes
	Net income				$	139			$	141			$	372			$	365
	Other comprehensive income (net of income taxes):
		Change in net unrealized gain on cash-flow hedges				—				2				2				2
		Unrealized gain on marketable securities				—				1				2				1
			Total other comprehensive income			—				3				4				3
Total comprehensive income					$	139			$	144			$	376			$	368

See Combined Notes to Consolidated Financial Statements

14

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

					Nine Months
					Ended
					September 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	372			$	365
	Adjustments to reconcile net income to net cash flows provided by operating activities:
		Depreciation and amortization				395				370
		Deferred income taxes and amortization of investment tax credits				(72	)			(76	)
		Provision for uncollectible accounts				30				38
		Equity in losses of unconsolidated affiliates				19				—
		Other operating activities				4				(2	)
		Changes in assets and liabilities:
			Receivables			4				25
			Inventories			(15	)			(44	)
			Deferred energy costs			52				(33	)
			Prepaid taxes			(49	)			(46	)
			Other current assets			(2	)			(4	)
			Accounts payable, accrued expenses and other current liabilities			35				52
			Receivables and payables to affiliates			9				68
			Pension and non-pension postretirement benefits obligations			20				45
			Other noncurrent assets and liabilities			(12	)			(1	)
Net cash flows provided by operating activities						790				757
Cash flows from investing activities
	Capital expenditures					(162	)			(191	)
	Changes in Exelon intercompany money pool investment					(26	)			—
	Change in restricted cash					—				132
	Other investing activities					2				(2	)
Net cash flows used in investing activities						(186	)			(61	)
Cash flows from financing activities
	Issuance of long-term debt					75				450
	Retirement of long-term debt					(75	)			(709	)
	Issuance of long-term debt to affiliate					—				103
	Retirement of long-term debt to PECO Energy Transition Trust					(286	)			—
	Change in short-term debt					(46	)			(188	)
	Retirement of mandatorily redeemable preferred securities					—				(50	)
	Retirement of preferred stock					—				(50	)
	Dividends paid on preferred and common stock					(279	)			(248	)
	Contribution from parent					106				17
	Other financing activities					2				(2	)
Net cash flows used in financing activities						(503	)			(677	)
Increase in cash and cash equivalents						101				19
Cash and cash equivalents at beginning of period						44				63
Cash and cash equivalents at end of period					$	145			$	82

See Combined Notes to Consolidated Financial Statements

15

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

				September 30,				December 31,
(In millions)				2004				2003
ASSETS
Current assets
	Cash and cash equivalents			$	145			$	44
	Accounts receivable, net
		Customer			325				363
		Other			35				27
	Inventories, at average cost
		Gas			112				99
		Materials and supplies			9				7
	Investment in Exelon intercompany money pool				26				—
	Deferred income taxes				32				64
	Deferred energy costs				29				81
	Prepaid taxes				50				1
	Other				12				10
		Total current assets			775				696
Property, plant and equipment, net					4,305				4,256
Deferred debits and other assets
	Regulatory assets				4,931				5,226
	Investments				19				20
	Investment in affiliates				108				123
	Receivables from affiliates				15				13
	Pension asset				78				68
	Other				14				8
		Total deferred debits and other assets			5,165				5,458
Total assets				$	10,245			$	10,410

See Combined Notes to Consolidated Financial Statements

16

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Commercial paper			$	—			$	46
	Payables to affiliates				161				150
	Long-term debt to PECO Energy Transition Trust due within one year				272				153
	Accounts payable				64				92
	Accrued expenses				293				237
	Other				42				35
		Total current liabilities			832				713
Long-term debt					1,356				1,359
Long-term debt to PECO Energy Transition Trust					3,291				3,696
Long-term debt to other affiliates					184				184
Deferred credits and other liabilities
	Deferred income taxes				2,886				2,986
	Unamortized investment tax credits				20				22
	Non-pension postretirement benefits obligation				317				287
	Other				140				147
		Total deferred credits and other liabilities			3,363				3,442
		Total liabilities			9,026				9,394
Commitments and contingencies
Shareholders’ equity
	Common stock				2,000				1,999
	Receivable from parent				(1,518	)			(1,623	)
	Preferred stock				87				87
	Retained earnings				639				546
	Accumulated other comprehensive income				11				7
		Total shareholders’ equity			1,219				1,016
Total liabilities and shareholders’ equity				$	10,245			$	10,410

See Combined Notes to Consolidated Financial Statements

17

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EXELON GENERATION COMPANY, LLC

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

					Three Months								Nine Months
					Ended								Ended
					September 30,								September 30,
					2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues				$	1,009			$	1,180			$	3,159			$	3,055
	Operating revenues from affiliates					1,244				1,357				2,994				3,246
		Total operating revenues				2,253				2,537				6,153				6,301
Operating expenses
	Purchased power					743				1,096				1,814				2,531
	Purchased power from affiliates					—				144				11				350
	Fuel					379				449				1,427				1,156
	Impairment of Boston Generating, LLC long-lived assets					—				945				—				945
	Operating and maintenance					366				453				1,445				1,261
	Operating and maintenance from affiliates					66				54				200				136
	Depreciation and amortization					95				51				218				142
	Taxes other than income					42				28				137				115
		Total operating expenses				1,691				3,220				5,252				6,636
Operating income (loss)						562				(683	)			901				(335	)
Other income and deductions
	Interest expense					(44	)			(22	)			(120	)			(52	)
	Interest expense to affiliates					(1	)			(3	)			(3	)			(11	)
	Equity in earnings (losses) of unconsolidated affiliates					(5	)			53				(7	)			90
	Other, net					5				(53	)			129				(238	)
		Total other income and deductions				(45	)			(25	)			(1	)			(211	)
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles						517				(708	)			900				(546	)
Income taxes						198				(280	)			343				(209	)
Income (loss) before minority interest and cumulative effect of changes in accounting principles						319				(428	)			557				(337	)
Minority interest						—				—				10				(2	)
Income (loss) before cumulative effect of changes in accounting principles						319				(428	)			567				(339	)
Cumulative effect of changes in accounting principles (net of income taxes of $22 and $70 for the nine months ended September 30, 2004 and 2003, respectively)						—				—				32				108
Net income (loss)						319				(428	)			599				(231	)
	Other comprehensive income (loss), net of income taxes
		Change in net unrealized gain (loss) on cash-flow hedges				77				147				(70	)			30
		Unrealized gain (loss) on marketable securities				7				1				15				(1	)
		Foreign currency translation adjustment				1				—				(3	)			—
		SFAS No. 143 transition adjustment				—				—				—				168
		Interest in other comprehensive income of unconsolidated affiliates				—				1				2				9
			Total other comprehensive income (loss)			85				149				(56	)			206
Total comprehensive income (loss)					$	404			$	(279	)		$	543			$	(25	)

     See Combined Notes to Consolidated Financial Statements

18

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

					Nine Months
					Ended
					September 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income (loss)				$	599			$	(231	)
	Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
		Depreciation, amortization and accretion, including nuclear fuel				745				594
		Cumulative effect of changes in accounting principles (net of income taxes)				(32	)			(108	)
		Gain on sale of investments				(91	)			(2	)
		Impairment of investment				—				255
		Impairment of long-lived assets				—				950
		Deferred income taxes and amortization of investment tax credits				159				(393	)
		Provision for uncollectible accounts				3				1
		Equity in (earnings) losses of unconsolidated affiliates				7				(90	)
		Net realized gains on nuclear decommissioning trust funds				(2	)			(9	)
		Other operating activities				(69	)			8
		Changes in assets and liabilities:
			Receivables			298				(81	)
			Receivables and payables to affiliates, net			(5	)			254
			Inventories			—				(10	)
			Accounts payable, accrued expenses and other current liabilities			(46	)			69
			Other current assets			66				(16	)
			Net realized and unrealized mark-to-market and hedging transactions			(18	)			1
			Pension and non-pension postretirement benefits obligations			(89	)			(65	)
			Other noncurrent assets and liabilities			(17	)			14
Net cash flows provided by operating activities						1,508				1,141
Cash flows from investing activities
	Capital expenditures					(608	)			(733	)
	Proceeds from liquidated damages					—				92
	Proceeds from nuclear decommissioning trust fund sales					1,485				1,880
	Investment in nuclear decommissioning trust funds					(1,687	)			(2,043	)
	Investment in Exelon intercompany money pool					(17	)			—
	Note receivable from affiliate					—				20
	Net cash increase from consolidation of Sithe Energies, Inc. and Exelon Energy Company					24				—
	Change in restricted cash					(8	)			(25	)
	Proceeds from sale of long-lived assets					42				—
	Proceeds from sale of subsidiaries					24				—
	Other investing activities					13				12
Net cash flows used in investing activities						(732	)			(797	)
Cash flows from financing activities
	Issuance of long-term debt					—				211
	Retirement of long-term debt					(29	)			(4	)
	Payment on acquisition note payable to Sithe Energies, Inc.					(27	)			(210	)
	Changes in Exelon intercompany money pool borrowings					(445	)			(178	)
	Distribution to member					(170	)			(116	)
	Other financing activities					7				(2	)
Net cash flows used in financing activities						(664	)			(299	)
Increase in cash and cash equivalents						112				45
Cash and cash equivalents at beginning of period						158				58
Cash and cash equivalents at end of period					$	270			$	103
Supplemental cash flow information
	Noncash investing and financing activities:
		Consolidation of Sithe Energies, Inc. pursuant to FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities”			$	85			$	—
		Contribution of Exelon Energy Company from Exelon Corporation				(9	)			—
		Distribution to member				—				17

See Combined Notes to Consolidated Financial Statements

19

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	270			$	158
	Restricted cash and investments				163				75
	Accounts receivable, net
		Customer			477				389
		Other			119				402
	Mark-to-market derivative assets				403				322
	Receivables from affiliates				333				421
	Inventories, at average cost
		Fossil fuel			79				98
		Materials and supplies			268				259
	Notes receivable				23				5
	Deferred income taxes				34				40
	Assets held for sale				—				36
	Other				141				233
		Total current assets			2,310				2,438
Property, plant and equipment, net					6,914				7,106
Deferred debits and other assets
	Nuclear decommissioning trust funds				4,943				4,721
	Investments				103				65
	Receivable from affiliate				22				22
	Pension asset				216				79
	Mark-to-market derivative assets				422				100
	Other				554				118
		Total deferred debits and other assets			6,260				5,105
Total assets				$	15,484			$	14,649

See Combined Notes to Consolidated Financial Statements

20

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

				September 30,				December 31,
				2004				2003
(In millions)
Liabilities and member’s equity
Current liabilities
	Long-term debt due within one year			$	61			$	1,068
	Accounts payable				853				848
	Mark-to-market derivative liabilities				655				581
	Payables to affiliates				31				1
	Notes payable to affiliates				—				506
	Accrued expenses				375				423
	Other				100				126
		Total current liabilities			2,075				3,553
Long-term debt					2,444				1,649
Deferred credits and other liabilities
	Deferred income taxes				429				195
	Unamortized investment tax credits				212				218
	Asset retirement obligation				3,472				2,996
	Pension obligation				21				21
	Non-pension postretirement benefits obligation				604				555
	Spent nuclear fuel obligation				875				867
	Payable to affiliates				1,274				1,195
	Mark-to-market derivative liabilities				391				133
	Other				302				308
		Total deferred credits and other liabilities			7,580				6,488
		Total liabilities			12,099				11,690
Commitments and contingencies
Minority interest of consolidated subsidiary					55				3
Member’s equity
	Membership interest				2,495				2,490
	Undistributed earnings				1,031				602
	Accumulated other comprehensive loss				(196	)			(136	)
		Total member’s equity			3,330				2,956
Total liabilities and member’s equity				$	15,484			$	14,649

See Combined Notes to Consolidated Financial Statements

21

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

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, wholesale generation and other businesses discussed below (see Note 17 — Segment Information). The energy delivery businesses (Energy Delivery) include the purchase and sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and PECO Energy Company (PECO) in southeastern Pennsylvania and the purchase and sale of natural gas and related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business consists of the electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation), the competitive retail sales business of Exelon Energy Company, equity interests in Sithe Energies Inc. (Sithe) and certain generation projects. The enterprises business segment consists of the remaining infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments weighted towards the communications and energy services industries. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. See Note 3 — Acquisitions and Dispositions for information regarding the disposition of businesses within the enterprises segment.

      The consolidated financial statements of Exelon, ComEd, PECO and Generation each include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, 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 the registrant as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon, ComEd, PECO and Generation do not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.

      In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Sithe, a 50% owned subsidiary of Generation, was consolidated in the financial statements of Exelon and Generation as of March 31, 2004. Certain trusts and limited partnerships that are financing subsidiaries of ComEd and PECO have issued debt or mandatorily redeemable preferred securities. Due to the adoption of FIN No. 46-R, these trusts and limited partnerships are no longer consolidated within the financial statements of Exelon, ComEd or PECO as of December 31, 2003, or as of July 1, 2003 for PECO Energy Capital Trust IV (PECO Trust IV). See Note 2 — New Accounting Principles for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe and the deconsolidation of these financing entities.

      The accompanying consolidated financial statements as of September 30, 2004 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, 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 share and per-share amounts included in Exelon’s consolidated financial statements and combined notes to consolidated financial statements have been adjusted for all periods presented to reflect a 2-for-1 stock split of Exelon’s common stock. See Note 14 — Earnings Per Share and Shareholders’ Equity for additional information regarding the stock split. The December 31, 2003 Consolidated Balance Sheets were derived from audited financial statements. These combined notes to consolidated financial statements do not include all disclosures required by GAAP. Certain prior-year amounts have been reclassified for comparative purposes.

22

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 or incorporated by reference in ITEM 8 of their Annual Reports on Form 10-K for the year ended December 31, 2003.

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

	New Accounting Principles with a Cumulative Effect upon Adoption

	FIN No. 46 and FIN No. 46-R

      The FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN No. 46), in January 2003 and subsequently issued its revision in FIN No. 46-R in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46 was effective for Exelon’s variable interest entities created after January 31, 2003 and FIN No. 46-R was effective December 31, 2003 for Exelon’s other variable interest entities that were considered to be special-purpose entities. FIN No. 46-R applied to all other variable interest entities as of March 31, 2004.

      Exelon and Generation consolidated Sithe as of March 31, 2004 pursuant to the provisions of FIN No. 46-R and recorded income of $32 million (net of income taxes) as a result of the elimination of a guarantee of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. Generation is a 50% owner of Sithe, and Exelon and Generation had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities. See Note 4 — Sithe for additional information on the consolidation of Sithe.

      PECO Trust IV, a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of Exelon and PECO pursuant to the provisions of FIN No. 46 as of July 1, 2003. Pursuant to the provisions of FIN No. 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust, were deconsolidated from the financial statements of Exelon and ComEd, and the other financing trusts of PECO, namely PECO Energy Capital Trust III (PECO Trust III) and PECO Energy Transition Trust (PETT), were deconsolidated from the financial statements of Exelon and PECO. Amounts owed to these financing trusts were recorded as debt to financing trusts or affiliates within the Consolidated Balance Sheets at September 30, 2004 and December 31, 2003 as follows:

		September 30, 2004				December 31, 2003
Exelon		$	5,523			$	6,070
ComEd			1,776				2,037
PECO			3,747				4,033

      This change in presentation had no effect on the net income of Exelon, ComEd or PECO. In accordance with FIN No. 46-R, prior periods were not reclassified.

	SFAS No. 143

      FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Exelon, ComEd, PECO and Generation were required to adopt SFAS No. 143 as of January 1, 2003.

23

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A significant retirement obligation is Generation’s obligation to decommission its nuclear plants at the end of their license lives. See Note 13 — Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments for additional information.

      Exelon recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of SFAS No. 143 in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:

Generation (net of income taxes of $52)		$	80
Generation’s investments in AmerGen Energy Company, LLC and Sithe (net of income taxes of $18)			28
ComEd (net of income taxes of $0)			5
Enterprises (net of income taxes of $(1))			(1	)
Total		$	112

      The cumulative effect of the change in accounting principle in adopting SFAS No. 143 had no effect on PECO’s income statement.

	Other New Accounting Principles

	EITF 03-11

      In July 2003, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11), which was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Exelon and Generation adopted EITF 03-11 as of January 1, 2004 and presented $272 million of revenue, $271 million of purchased power and $1 million of fuel expense net within revenues during the three months ended September 30, 2004 and $724 million of revenue, $715 million of purchased power and $9 million of fuel expense net within revenues during the nine months ended September 30, 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on the net income of Exelon or Generation. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:

	Exelon

						EITF 03-11
For the Three Months Ended September 30, 2003		As Reported				Impact				Pro Forma
Operating revenues			$4,441			$	(344	)			$4,097
Purchased power			1,312				(330	)			982
Fuel expense			551				(14	)			537

24

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

						EITF 03-11
For the Nine Months Ended September 30, 2003		As Reported				Impact				Pro Forma
Operating revenues		$	12,236			$	(829	)		$	11,407
Purchased power			3,075				(778	)			2,297
Fuel expense			1,908				(51	)			1,857

	Generation

						EITF 03-11
For the Three Months Ended September 30, 2003		As Reported				Impact				Pro Forma
Operating revenues			$2,537			$	(344	)			$2,193
Purchased power			1,240				(330	)			910
Fuel expense			449				(14	)			435

						EITF 03-11
For the Nine Months Ended September 30, 2003		As Reported				Impact				Pro Forma
Operating revenues			$6,301			$	(829	)			$5,472
Purchased power			2,881				(778	)			2,103
Fuel expense			1,156				(51	)			1,105

	FSP FAS 106-2

      Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Actuarial equivalence has not yet been formally defined by the U.S. Department of Health and Human Services and thus is a matter of judgment by the plan sponsor and its actuaries. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), which provides transition guidance for accounting for the effects of the Prescription Drug Act and supersedes FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.

      During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a re-measurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Upon adoption, the effect of the subsidy on benefits attributable to past service was accounted for as an actuarial experience gain, resulting in a decrease of the APBO of approximately $177 million. The annualized reduction in the net periodic postretirement benefit cost is estimated to be approximately $32 million compared to the annual cost calculated without considering the effects of the Prescription Drug Act. The effect of the subsidy on the components of net periodic

25

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

postretirement benefit cost for the three and nine months ended September 30, 2004 included in the consolidated financial statements and Note 11 — Retirement Benefits was as follows:

		Three Months				Nine Months
		Ended				Ended
		September 30, 2004				September 30, 2004
Amortization of the actuarial experience gain		$	3			$	11
Reduction in current period service cost			2				4
Reduction in interest cost on the APBO			3				9

      The following table presents Exelon’s net income and earnings per share for the three months ended March 31, 2004 as if FSP FAS 106-2 had been adopted as of January 1, 2004. Previously reported historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

			Three Months
			Ended
			March 31, 2004
Net income — as reported			$	406
Reduction in net periodic postretirement benefit expense(a)				6
Adjusted net income			$	412
Earnings per share:
	Basic — as reported		$	0.62
	Basic — as adjusted		$	0.63
	Diluted — as reported		$	0.61
	Diluted — as adjusted		$	0.62

---

(a)	A portion of the net periodic postretirement benefit cost is capitalized within Exelon’s Consolidated Balance Sheets. The reduction in net periodic postretirement benefit expense due to the Prescription Drug Act is not taxable to Exelon.

     The following table presents net income of ComEd and Generation and net income on common stock of PECO for the three months ended March 31, 2004 as if FSP FAS 106-2 was adopted as of January 1, 2004. Historical financial information for the three months ended March 31, 2004 has been adjusted in the table below and will be adjusted when presented for comparative purposes in future periods to reflect a reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

Three Months Ended March 31, 2004		ComEd				PECO				Generation
Net income — as reported		$	182			$	130	(a)		$	99
Reduction in net periodic postretirement benefit expense(b)			2				1				3
Adjusted net income		$	184			$	131			$	102

---

(a)	Represents PECO’s net income on common stock.

(b)	A portion of the net periodic postretirement benefit cost is capitalized within the Consolidated Balance Sheets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	EITF 03-1

      In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1). EITF 03-1 provides guidance for evaluating whether an investment is other-than-temporarily impaired. Exelon adopted the disclosure requirements of EITF 03-1 for investments accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” within its financial statements for the year ended December 31, 2003. On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,’ ” which delayed the effective date of the application guidance on impairment of securities included within EITF 03-1. Exelon, ComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-1.

	EITF 03-16

      In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). The EITF concluded that if investors in a limited liability company have specific ownership accounts, they should follow the guidance prescribed in Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” and EITF Topic No. D-46, “Accounting for Limited Partnership Investments.” Otherwise, investors should follow the significant influence model prescribed in Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” EITF 03-16 was effective for Exelon, ComEd, PECO and Generation during the third quarter of 2004. Exelon recorded a charge of $9 million (net of an income tax benefit of $5 million) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard as of July 1, 2004. This charge related to certain investments in limited liability partnerships held by Enterprises. The adoption of this standard had no effect on the financial statements of ComEd, PECO or Generation.

3.	Acquisitions and Dispositions (Exelon and Generation)

	Sale of Ownership Interest in Boston Generating, LLC (Exelon and Generation)

      On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of their indirect wholly owned subsidiary, Boston Generating, LLC (Boston Generating), which owns the companies that own the Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).

      The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The Federal Energy Regulatory Commission (FERC) approved the sale of Boston Generating in May 2004. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity and its contractors in a separate transaction on September 1, 2004.

      In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities. See Note 15 — Commitments and Contingencies for information regarding the settlement of litigation associated with the projects.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In connection with the decision to transition out of Boston Generating and the generating units, Generation recorded during the third quarter of 2003 an impairment charge of its long-lived assets pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income and Comprehensive Income. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Exelon and Generation recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income in the second quarter of 2004. In connection with the sale, Exelon and Generation recorded a liability associated with an existing guarantee by their subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. Due to Generation’s ongoing involvement through the continued existence of this guarantee and in accordance with SFAS No. 144, the results of Boston Generating have not been classified as a discontinued operation within the Consolidated Statements of Income and Comprehensive Income of Exelon and Generation. See Note 15 — Commitments and Contingencies for further information regarding the guarantee.

      Boston Generating was reported in the Generation segment of Exelon’s consolidated financial statements prior to its sale. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from the Consolidated Balance Sheets of both Exelon and Generation. Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2004 and 2003 include the following financial results related to Boston Generating:

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
		2004				2003				2004				2003
Operating revenues		$	—			$	224			$	248			$	407
Operating loss			—				(962	)			(47	)			(944	)
Net income (loss)(a)			—				(581	)			24				(572	)

---

(a)	Net income for the nine months ended September 30, 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004.

	Disposition of Enterprises Entities (Exelon)

      Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million, resulting in a pre-tax gain of $45 million. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, resulting in prepayment penalties of $9 million. On September 29, 2004, Enterprises sold ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, resulting in a pre-tax loss of $3 million.

      Exelon Services, Inc. During the nine months ended September 30, 2004, Enterprises disposed of substantially all of the operating components of Exelon Services, Inc. (Services), including Exelon Solutions, most mechanical services businesses and the Integrated Technology Group. Total expected proceeds (subject to post-closing adjustments) and the net gain on sale (before income taxes) recorded during 2004 related to the disposition of these businesses of Services were $35 million and $9 million, respectively. As of

28

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2004, Services had remaining assets and liabilities of $66 million and $14 million, respectively, which primarily represented the corporate center operations.

      PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.

      InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. (InfraSource). See the Notes to Consolidated Financial Statements in Exelon’s 2003 Form 10-K for further information regarding this sale. A $30 million subordinated note receivable that was received as part of the sale proceeds at closing was collected in full prior to its maturity during the second quarter of 2004, resulting in income of $18 million. Enterprises’ results of operations for the three and nine months ended September 30, 2004 compared to the same periods in 2003 were significantly affected by the sale of InfraSource. In connection with the transaction, Enterprises entered into an agreement that may result in certain payments to InfraSource if the amount of services Exelon purchases from InfraSource during the period from closing through 2006 is below specified thresholds. Due to Exelon’s ongoing involvement with InfraSource through the continued existence of this agreement and in accordance with SFAS No. 144, the results of InfraSource have not been classified as a discontinued operation within Exelon’s Consolidated Statements of Income and Comprehensive Income.

      The results of Thermal and Services have been included in income from continuing operations within Exelon’s Consolidated Statements of Income and Comprehensive Income (as opposed to discontinued operations) as the impact of these entities on Exelon’s consolidated financial statements was not significant.

	Exelon Energy Company (Generation)

      Effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. The transaction had no effect on the assets and liabilities of Exelon Energy Company, which were previously reported as a part of the Enterprises segment. Beginning in 2004, Exelon Energy Company’s assets and liabilities and results of operations are included in Generation’s financial statements. Generation and Enterprises’ 2003 segment information has been adjusted to reflect this transfer in Note 17 — Segment Information.

      The following summary represents the assets, liabilities, and equity of Exelon Energy Company, before intercompany eliminations, that were transferred to Generation as of January 1, 2004:

Current assets (including $5 million of cash)		$	119
Property, plant and equipment			2
Deferred debits and other assets			13
Total assets		$	134
Current liabilities		$	126
Deferred credits and other liabilities			10
Member’s equity			(2	)
Total liabilities and member’s equity		$	134

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the transfer of Exelon Energy Company to Generation as if the transaction had occurred on January 1, 2003 and was included in Generation’s results from that date.

	AmerGen Energy Company, LLC (Exelon and Generation)

      On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $277 million. The allocation of fair value of long-lived assets will be affected by the finalization of the purchase price based on the completion of the review of the closing balances of AmerGen and the British Energy holding companies that were acquired in this transaction. Generation and British Energy are currently negotiating the finalization of the purchase price adjustments and anticipate completion of these negotiations by the end of the fourth quarter of 2004.

      Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. For the three and nine months ended September 30, 2003, Generation recorded equity in earnings of unconsolidated affiliates related to its investment in AmerGen of $47 million and $131 million, respectively, including income of $47 million ($28 million, net of tax) for the cumulative effect of the adoption of SFAS 143 on January 1, 2003. Generation recorded $133 million and $310 million, respectively, of purchased power from AmerGen for the three and nine months ended September 30, 2003, respectively. The book value of Generation’s investment in AmerGen prior to the purchase was $311 million. For the three and nine months ended September 30, 2004, AmerGen’s assets and liabilities and results of operations are included in Generation’s financial statements.

      See Note 5 — Selected Pro Forma and Consolidating Financial Information for the effect of the acquisition of the remaining 50% interest in AmerGen by Generation as if the transaction had occurred on January 1, 2003 and was included in Exelon and Generation’s results from that date.

	Synthetic Fuel-Producing Facilities (Exelon)

      Synthetic fuel-producing facilities chemically change coal, including waste and marginal coal, into a fuel used at power plants. In November 2003, Exelon purchased interests in two synthetic fuel-producing facilities. The purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. The notes payable recorded for the purchase of the facilities were $238 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset which is amortized as the tax credits are earned. In April 2004, the Internal Revenue Service (IRS) issued two private letter rulings that affirmed that the process used by the facilities will produce a solid synthetic fuel that qualifies for tax credits under Section 29 of the Internal Revenue Code.

      In July 2004, Exelon purchased an interest in a limited partnership that indirectly owns four synthetic fuel-producing facilities. Exelon’s purchase price for these facilities included a combination of cash, a note payable and contingent consideration dependent upon the production levels of the facilities. The note payable recorded for the purchase of the facilities was $22 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset which is amortized as the tax credits are earned. Private letter rulings have been received by the partnership that affirm that the process used by the facilities will produce a solid synthetic fuel that qualifies for tax credits under Section 29 of the Internal Revenue Code.

      Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits as the annual average wellhead price per barrel of domestic crude oil increases

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

into an inflation-adjusted phase-out range. For 2003, the tax credit would have begun to phase-out when the annual average wellhead price per barrel of domestic crude oil exceeded $50.14 per barrel and would have been completely phased out when the annual average wellhead price per barrel of domestic crude oil reached $62.94 per barrel. The 2004 and 2005 phase-out range will be calculated using inflation rates published in 2005 and 2006, respectively, by the Internal Revenue Service.

      Due to the low price of domestic crude oil during the first part of 2004, the phase-out is not expected to affect Exelon’s tax credits or net income from the facilities for 2004. If domestic crude oil prices remain high in 2005, the tax credits and net income generated by the investments may be reduced substantially. In addition, Exelon has recorded an intangible asset related to its investments in these facilities that could become impaired if domestic crude oil prices continue to increase in the future. See Note 8 — Intangible Assets for additional information regarding this intangible asset.

      Exelon’s investments in synthetic fuel-producing facilities are not consolidated within Exelon’s financial statements as Exelon does not have a controlling financial interest in these facilities. See Note 12 — Income Taxes for information regarding the effect of these investments in synthetic fuel-producing facilities on Exelon’s effective income tax rate.

	Assets and Liabilities Held for Sale (Exelon, Generation and Enterprises)

      During the third quarter of 2004, the remainder of Sithe assets and liabilities classified as held for sale at June 30, 2004 were sold. During the second quarter of 2004, Sithe completed the sale of certain of its gas, hydroelectric, and the Australian businesses, which represented an aggregate of $160 million and $143 million of assets and liabilities held for sale, respectively, at March 31, 2004, recognizing a gain on the sale of these businesses of $6 million during the period.

      During 2004, Enterprises sold the assets and liabilities of Thermal and Services that were classified as held for sale at December 31, 2003. See “Disposition of Enterprises Entities” above for additional information regarding these dispositions.

4.	Sithe (Exelon and Generation)

      Sithe is primarily engaged in the ownership and operation of electric wholesale generating facilities in North America. At September 30, 2004, Sithe operated nine power units with total average net capacity of 1,323 megawatts (MW). Sithe also has a 49.5% interest in TEG, consisting of two 230-MW projects in Mexico, which commenced commercial operations during the second quarter of 2004. See Note 19 — Subsequent Events for information on the transfer of Sithe’s interests in the two generating facilities in Mexico to Generation.

      On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe (Generation owned 49.9% prior to November 25, 2003). See the 2003 Form 10-K for further details regarding these transactions. Both Generation and Reservoir’s 50% interests in Sithe were subject to put and call options that could result in either party owning 100% of Sithe.

      On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call is subject to the receipt of state and Federal regulatory approvals.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Generation’s intent is to fully divest its interest in Sithe, and it is actively pursuing opportunities to dispose of Sithe. Generation believes that exercising its call option will provide it with greater certainty of a timely exit from Sithe on favorable terms and conditions.

      Exelon and Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN No. 46-R. See Note 2 — New Accounting Principles for further discussion.

      As a result of the series of transactions in November 2003 referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Exelon and Generation’s results of operations beginning April 1, 2004.

      Sithe has entered into tolling arrangements (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe has entered into an energy purchase agreement (Energy Purchase Agreement) with Consolidated Edison Company relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement on March 31, 2004 of approximately $91 million and $282 million, respectively, which have been recorded as intangible assets on Exelon’s and Generation’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models.

      The intangible assets representing the Tolling Agreement and the Energy Purchase Agreement are being amortized on a straight-line basis over the lives of the associated agreements. The allocation of fair value related to the valuation of long-lived assets is preliminary and is anticipated to be finalized in the fourth quarter of 2004. Sithe’s intangible assets are included in other non-current assets on Generation’s Consolidated Balance Sheet. See Note 8 — Intangible Assets for further information regarding Sithe’s intangible assets as of September 30, 2004.

      In connection with the consolidation of Sithe, certain indemnification guarantees previously recorded in accordance with the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45), were reversed in accordance with FIN No. 45, as Generation can no longer record liabilities associated with guarantees for the performance of a consolidated entity. The reversal of the guarantees resulted in Exelon and Generation recording income of $32 million (net of $22 million of income taxes) as a cumulative effect of a change in accounting principle. The condensed consolidating financial information included in Note 5 — Selected Pro Forma and Consolidating Financial Information presents the financial position of Exelon, Generation and Sithe, as well as consolidating entries related primarily to acquisition notes payable and receivables between Generation and Sithe.

      The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the three months ended September 30, 2004, Generation recorded no equity method income or loss as Sithe is consolidated in Generation’s results. Generation recorded $2 million of equity method losses in the first quarter of 2004 prior to the consolidation of Sithe’s results of operations. Generation recorded equity method income related to Sithe of $6 million for the three and nine months ended September 30, 2003, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Substantially all of Sithe’s property, plant and equipment and project agreements secure Sithe’s outstanding long-term debt, which consists primarily of project debt. During 2003, Sithe entered into an agreement with Exelon and Generation under which Exelon would obtain letters of credit to support contractual obligations of Sithe and its subsidiaries. As of September 30, 2004, Exelon has obtained $59 million of letters of credit in support of Sithe’s obligations not including the $50 million letter of credit that is not guaranteed by Exelon. With the exception of the issuance of letters of credit to support contractual obligations, the creditors of Sithe have no recourse against the general credit of Exelon or Generation.

      The following table details the Sithe balance sheet classification of mark-to-market energy contract net assets recorded as of September 30, 2004:

Current assets			$	25
Non-current assets				238
	Total mark-to-market energy contract assets			263
Current liabilities				(13	)
Non-current liabilities				(141	)
	Total mark-to-market energy contract liabilities			(154	)
Total mark-to-market energy contract net assets			$	109

      The financial statements of Sithe’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income and Comprehensive Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Income and Comprehensive Income and accordingly have no effect on net income.

5.	Selected Pro Forma and Consolidating Financial Information

	Exelon

      The following unaudited pro forma financial information gives effect to the acquisition of the remaining 50% interest in AmerGen by Generation and the sale of Boston Generating by Generation, in each case, as if the transaction had occurred on January 1, 2003 and was included in or excluded from Exelon’s results from that date.

						Acquisition				Sale of								Pro Forma
		Exelon				of 50% of				Boston				Eliminating				Exelon
Three Months Ended September 30, 2003		As Reported				AmerGen				Generating				Entries(a)				Consolidated
Total operating revenues			$4,441			$	222			$	224			$	(133	)			$4,306
Operating income (loss)			6				87				(962	)			—				1,055
Income (loss) before cumulative effect of changes in accounting principles			(102	)			96				(581	)			(47	)			528

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(a)	Represents the elimination of intercompany revenues at AmerGen and equity in earnings from AmerGen in 2003.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

						Acquisition				Sale of								Pro Forma
		Exelon				of 50% of				Boston				Eliminating				Exelon
Nine Months Ended September 30, 2003		As Reported				AmerGen				Generating				Entries(a)				Consolidated
Total operating revenues		$	12,236			$	529			$	407			$	(310	)		$	12,048
Operating income (loss)			1,615				146				(944	)			—				2,705
Income before cumulative effect of changes in accounting principles			519				168				(572	)			(84	)			1,175

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(a)	Represents the elimination of intercompany revenues at AmerGen and equity in earnings from AmerGen in 2003.

     The above unaudited pro-forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if the transactions had actually occurred on January 1, 2003, nor of the results that might be obtained in the future.

	Exelon Condensed Consolidating Balance Sheet at September 30, 2004

      The following condensed consolidating financial information presents the financial position of Exelon and Sithe, as well as eliminating entries, related primarily to acquisition notes payable and receivables between Generation and Sithe.

														Exelon
										Eliminating				Consolidated
September 30, 2004		Exelon				Sithe				Entries				(As Reported)
Assets
Current assets		$	3,933			$	282			$	(161	)		$	4,054
Property, plant and equipment, net			20,452				272				—				20,724
Other non-current assets			16,553				770				(42	)			17,281
Total assets		$	40,938			$	1,324			$	(203	)		$	42,059
Liabilities and shareholders’ equity
Current liabilities		$	4,418			$	248			$	(161	)		$	4,505
Long-term debt			11,953				803				—				12,756
Other long-term liabilities(a)			14,934				179				52				15,165
Shareholders’ equity(b)			9,633				94				(94	)			9,633
Total liabilities and shareholders’ equity		$	40,938			$	1,324			$	(203	)		$	42,059

---

(a)	Includes minority interest in consolidated subsidiaries.

(b)	Includes preferred securities of subsidiaries.

34

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Generation

      The following unaudited pro forma financial information gives effect to the acquisition of the remaining 50% interest in AmerGen, the transfer of Exelon Energy Company to Generation and the sale of Boston Generating, in each case, as if the transaction had occurred on January 1, 2003 and was included in or excluded from Generation’s results from that date.

																		Pro Forma
		Generation				Businesses				Businesses				Eliminating				Generation
Three Months Ended September 30, 2003		As Reported				Acquired(a)				Disposed(b)				Entries(c)				Consolidated
Total operating revenue		$	2,537			$	368			$	224			$	(186	)		$	2,495
Operating income (loss)			(683	)			82				(962	)			—				361
Income (loss) before cumulative effect of changes in accounting principles			(428	)			93				(581	)			(47	)			199

---

(a)	Consists of the acquisition of the remaining 50% interest in AmerGen and the transfer of Exelon Energy Company to Generation.

(b)	Consists of the sale of Boston Generating.

(c)	Represents the elimination of intercompany revenues at AmerGen and Exelon Energy and equity in earnings from AmerGen in 2003.

																		Pro Forma
		Generation				Businesses				Businesses				Eliminating				Generation
Nine Months Ended September 30, 2003		As Reported				Acquired(a)				Disposed(b)				Entries(c)				Consolidated
Total operating revenue		$	6,301			$	1,180			$	407			$	(472	)		$	6,602
Operating income (loss)			(335	)			128				(944	)			—				737
Income (loss) before cumulative effect of changes in accounting principles			(339	)			156				(572	)			(84	)			305

---

(a)	Consists of the acquisition of the remaining 50% interest in AmerGen and the transfer of Exelon Energy Company to Generation.

(b)	Consists of the sale of Boston Generating.

(c)	Represents the elimination of intercompany revenues at AmerGen and Exelon Energy and equity in earnings from AmerGen in 2003.

     The above unaudited, pro forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if these transactions had actually occurred on January 1, 2003, nor of the results that might be obtained in the future.

35

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Generation Condensed Consolidating Balance Sheet at September 30, 2004

      The following condensed consolidating financial information presents the financial position of Generation, Sithe and Exelon Energy, as well as eliminating entries related primarily to acquisition notes payable and receivables between Generation and Sithe.

																		Generation
										Exelon				Eliminating				Consolidated
September 30, 2004		Generation				Sithe				Energy				Entries				(As Reported)
Assets
Current assets		$	2,129			$	282			$	75			$	(176	)		$	2,310
Property, plant and equipment, net			6,641				272				1				—				6,914
Other non-current assets			5,521				770				11				(42	)			6,260
Total assets		$	14,291			$	1,324			$	87			$	(218	)		$	15,484
Liabilities and members’ equity
Current liabilities		$	1,934			$	248			$	69			$	(176	)		$	2,075
Long-term debt			1,641				803				—				—				2,444
Other long-term liabilities(a)			7,399				179				5				52				7,635
Members’ equity			3,317				94				13				(94	)			3,330
Total liabilities and members’ equity		$	14,291			$	1,324			$	87			$	(218	)		$	15,484

---

(a)	Includes minority interest in consolidated subsidiaries.

36

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

      Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by Accounting Principles Board No. 25, “Accounting for Stock Issued to Employees” and related interpretations and follows the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.” Accordingly, no compensation expense for stock options has been recognized within the Consolidated Statements of Income and Comprehensive Income. The tables below show the effect on net income and earnings per share for Exelon had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three and nine months ended September 30, 2004 and 2003:

	Exelon

			Three Months
			Ended
			September 30,
			2004				2003
Net income (loss) — as reported			$	568			$	(102	)
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes				(5	)			(5	)
Pro forma net income (loss)			$	563			$	(107	)
Earnings per share:
	Basic earnings (loss) — as reported		$	0.86			$	(0.16	)
	Basic earnings (loss) — pro forma		$	0.85			$	(0.16	)
	Diluted earnings (loss) — as reported		$	0.85			$	(0.16	)
	Diluted earnings (loss) — pro forma		$	0.84			$	(0.16	)

			Nine Months
			Ended
			September 30,
			2004				2003
Net income — as reported			$	1,501			$	631
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes				(15	)			(16	)
Pro forma net income			$	1,486			$	615
Earnings per share:
	Basic — as reported		$	2.27			$	0.97
	Basic — pro forma		$	2.25			$	0.95
	Diluted — as reported		$	2.25			$	0.96
	Diluted — pro forma		$	2.23			$	0.94

      The net income (loss) of ComEd, PECO and Generation for the three and nine months ended September 30, 2004 and 2003 would not have been significantly affected had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123.

37

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7.	Regulatory Issues (Exelon, ComEd and Generation)

	Exelon and ComEd

      PJM Integration. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations, including a provision to hold certain utilities in Michigan and Wisconsin harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004. In October 2004, ComEd entered into settlement agreements with nearly all the Michigan parties calling for a payment of approximately $2 million by ComEd. The agreements have been filed with the FERC and are awaiting approval. Settlement talks continue between ComEd and the remaining Wisconsin parties.

      Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and hearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. During the third quarter of 2004, a settlement agreement was reached and approved by the FERC, on an interim basis, which established new wholesale rates that became effective May 1, 2004. The FERC has allowed the proposed rates in the settlement agreement pending its final approval. However, because of the Illinois retail rate freeze and the method for calculating competitive transition charges, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006.

      Competitive Service Declaration. On November 14, 2002, the Illinois Commerce Commission (ICC) allowed ComEd, by operation of law, to revise its provider of last resort obligation to be the back-up energy supplier at market-based rates for customers with energy demands of at least three megawatts. About 370 of ComEd’s largest energy customers are affected, representing an aggregate supply obligation or load of approximately 2,500 megawatts. These customers accounted for 10% of ComEd’s 2003 MWh deliveries. These customers will not have a right to take bundled service after June 2006 or to come back to bundled rates if they choose an alternative supplier prior to June 2006. The parties to the March 2003 Agreement have committed, if specified market conditions exist, not to oppose a process for achieving a similar competitive declaration for customers having energy demands of one to three megawatts. To date, ComEd has not requested the competitive declaration for this second set of customers but continues to evaluate its options.

      On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff, to be available to customers who choose not to go to the competitive market to procure their electric power and energy. An appeal to each of the ICC’s orders was filed. On March 24, 2004, the Illinois Appellate Court issued its opinion affirming the ICC’s orders in both cases. The Court found that the ICC properly allowed ComEd’s competitive declaration for customers with loads of more than three megawatts to go into effect and that the ICC’s order approving the hourly rate was lawful.

	Exelon and Generation

      Service Life Extension. Upon the acquisition of AmerGen, Generation changed the accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the Nuclear Regulatory Commission (NRC) of extensions of the existing NRC operating licenses. Generation has not applied for license extensions at the AmerGen

38

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

facilities, but has announced its plan to file an extension request for the Oyster Creek Nuclear Generating Station (Oyster Creek), and is planning on filing for license extensions at Unit 1 at the Three Mile Island Nuclear Station (TMI) and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned extension filings for the Generation nuclear fleet.

8.	Intangible Assets (Exelon, ComEd and Generation)

	Exelon

      Goodwill. As of September 30, 2004 and December 31, 2003, Exelon had recorded goodwill of approximately $4.7 billion. Under the provisions of SFAS No. 142, goodwill is tested for impairment at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. Exelon will perform its annual goodwill impairment assessment in the fourth quarter of 2004. The changes in the carrying amount of goodwill by reportable segment (see Note 17 — Segment Information for further information regarding Exelon’s segments) for the periods ended September 30, 2004 and December 31, 2003 were as follows:

			Energy
			Delivery				Enterprises				Total
Balances as of January 1, 2003			$	4,916			$	76			$	4,992
Impairment losses				—				(72	)			(72	)
Adoption of SFAS No. 143:(a)
	Reduction of asset retirement obligation			(210	)			—				(210	)
	Cumulative effect of change in accounting principle			5				—				5
Resolution of certain tax matters				8				—				8
Other				—				(4	)			(4	)
Balances as of December 31, 2003				4,719				—				4,719
Resolution of certain tax matters				(9	)			—				(9	)
Other				(3	)			—				(3	)
Balances as of September 30, 2004			$	4,707			$	—			$	4,707

---

(a)		See Notes to Consolidated Financial Statements of Exelon in the 2003 Form 10-K for information regarding the adoption of SFAS No. 143.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			September 30, 2004												December 31, 2003
							Accumulated												Accumulated
			Gross				Amortization				Net				Gross				Amortization				Net
Amortized intangible assets:
	Energy purchase agreement(a)		$	384			$	(18	)		$	366			$	—			$	—			$	—
	Tolling agreement(a)			73				(3	)			70				—				—				—
	Synthetic fuel investments(b)			264				(40	)			224				241				(4	)			237
	Other			6				(5	)			1				6				—				6
Total amortized intangible assets				727				(66	)			661				247				(4	)			243
Other intangible assets:
	Intangible pension asset			186				—				186				186				—				186
Total			$	913			$	(66	)		$	847			$	433			$	(4	)		$	429

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(a)		See Note 4 — Sithe for a description of Sithe’s intangible assets.
(b)		See Note 3 — Acquisitions and Dispositions for a description of Exelon’s right to acquire tax credits through investments in synthetic fuel-producing facilities.

     Amortization expense related to these intangible assets was $21 million and $62 million for the three and nine months ended September 30, 2004, respectively, of which $8 million and $26 million for the three and nine months ended September 30, 2004, respectively, have been reflected as a reduction in revenues related to the energy purchase agreement and the tolling agreement. Amortization expense was not significant in 2003. Amortization expense related to these intangible assets is expected to be in the range of $100 million to $120 million annually from 2005 through 2007 and approximately $50 million in 2008.

	ComEd

      Goodwill. As of September 30, 2004 and December 31, 2003, ComEd had recorded goodwill of approximately $4.7 billion. Under the provisions of SFAS No. 142, goodwill is tested for impairment at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. ComEd will perform its annual goodwill impairment assessment in the fourth quarter of 2004. The changes in the carrying amount of goodwill for the periods ended September 30, 2004 and December 31, 2003 were as follows:

Balance as of January 1, 2003			$	4,916
Adoption of SFAS No. 143:(a)
	Reduction of asset retirement obligation			(210	)
	Cumulative effect of change in accounting principle			5
Resolution of certain tax matters				8
Balance as of December 31, 2003				4,719
Resolution of certain tax matters				(9	)
Other				(3	)
Balance as of September 30, 2004			$	4,707

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

---

(a)		See Notes to Consolidated Financial Statements of ComEd in the 2003 Form 10-K for information regarding the adoption of SFAS No. 143.

	Generation

      Other Intangible Assets. Generation’s other intangible assets consisted of the following:

			September 30, 2004												December 31, 2003
							Accumulated												Accumulated
			Gross				Amortization				Net				Gross				Amortization				Net
Amortized intangible assets:
	Energy purchase agreement(a)		$	384			$	(18	)		$	366			$	—			$	—			$	—
	Tolling agreement(a)			73				(3	)			70				—				—				—
	Other			6				(5	)			1				6				—				6
Total amortized intangible assets			$	463			$	(26	)		$	437			$	6			$	—			$	6

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(a)		See Note 4 — Sithe for a description of Sithe’s intangible assets.

     Amortization expense related to Generation’s intangible assets was $8 million and $26 million for the three and nine months ended September 30, 2004, which has been reflected as a reduction in revenue. Amortization expense was not significant in 2003. Amortization expense related to these intangible assets is expected to be $43 million annually from 2005 through 2009.

9.	Long-Term Debt (Exelon, ComEd, PECO and Generation)

	Credit Facility (Exelon, ComEd, PECO and Generation)

      At December 31, 2003, Exelon Corporate, along with ComEd, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. The terms of the new facilities are consistent with the previous facilities. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon Corporate, ComEd, PECO and Generation and to issue letters of credit.

	Boston Generating Credit Facility

      Approximately $1.0 billion of debt was outstanding under the non-recourse Boston Generating Credit Facility at December 31, 2003, all of which was reflected in the Consolidated Balance Sheets of Exelon and Generation as a current liability due to certain events of default under the Boston Generating Credit Facility.

      The outstanding debt under the Boston Generating Credit Facility was eliminated from the financial statements of Exelon and Generation upon the sale of Generation’s ownership interest in Boston Generating in May 2004. See Note 3 — Acquisitions and Dispositions for additional information regarding the sale.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Long-Term Debt

      Issuance of Long-Term Debt. During the nine months ended September 30, 2004, the following long-term debt was issued:

Interest

Company

Type

Rate

Maturity

Amount

PECO

First Mortgage Bonds

5.90%

May 1, 2034

$

75

Exelon

Note

6.00%

January 15, 2008

22

Total issuances

$

97

      Debt Retirements. During the nine months ended September 30, 2004, the following debt was retired, either through redemption or payment at maturity:

Company		Type				Interest Rate				Maturity				Amount
ComEd			Note				7.375	%			January 15, 2004			$	150
ComEd			Note				7.625	%			January 15, 2007				5
ComEd			Note				6.95	%			July 15, 2018				85
ComEd			Pollution Control Revenue Bonds				5.30	%			January 15, 2004				26
ComEd			Pollution Control Revenue Bonds				5.70	%			January 15, 2009				4
ComEd			Pollution Control Revenue Bonds				5.85	%			January 15, 2014				3
ComEd			Sinking Fund Debentures				3.125	%			April 1, 2004				1
ComEd			Sinking Fund Debentures				3.875	%			July 1, 2004				1
ComEd			Sinking Fund Debentures				4.625	%			July 1, 2004				1
ComEd			Sinking Fund Debentures				4.75	%			June 1, 2004				1
ComEd			First Mortgage Bonds				5.875	%			February 1, 2033				96
ComEd			First Mortgage Bonds				8.00	%			May 15, 2008				20
ComEd			First Mortgage Bonds				6.15	%			March 15, 2012				150
ComEd			First Mortgage Bonds				4.70	%			April 15, 2015				135
ComEd			First Mortgage Bonds				7.625	%			April 15, 2013				65
ComEd			First Mortgage Bonds				7.50	%			July 1, 2013				20
ComEd			First Mortgage Bonds				4.74	%			August 15, 2010				35
PECO			First and Refunding Mortgage Bonds				6.375	%			August 15, 2005				75
Enterprises			Note				7.68	%			June 30, 2023				11
Enterprises			Note				9.09	%			January 31, 2020				26
AmerGen			Note				6.33	%			August 8, 2009				10
Sithe			Note				8.50	%			June 30, 2007				15
Exelon			Note				8.00	%			January 20, 2008				26
Other															12
Total retirements														$	973

      During the three and nine months ended September 30, 2004, ComEd made scheduled payments of $82 million and $261 million, respectively, related to its obligation to the ComEd Transitional Funding Trust,

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and PECO made scheduled payments of $120 million and $286 million, respectively, related to its obligation to the PETT.

      During the nine months ending September 30, 2004, ComEd retired $768 million of long-term debt pursuant to Exelon’s accelerated liability management plan. ComEd funded the retirements through cash from operations, a return of investments in the intercompany money pool and collections on an intercompany note receivable from Unicom Investments, Inc. Exelon and ComEd recorded a charge of $106 million associated with the retirement of debt under the plan for the three and nine months ended September 30, 2004. This charge is included within other, net within Exelon’s Consolidated Statements of Income and Comprehensive Income. The components of this charge included the following: $63 million related to prepayment premiums; $11 million related to net unamortized premiums, discounts and debt issuance costs; $23 million of losses on reacquired debt previously deferred as regulatory assets; and $9 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets.

      Sithe Long-Term Debt. At September 30, 2004, the following long-term debt of Sithe was consolidated in Exelon’s and Generation’s Consolidated Balance Sheets as a result of the adoption of FIN No. 46-R. See Note 2 — New Accounting Principles and Note 4 — Sithe for further information regarding the consolidation of Sithe.

				Stated Interest								Face Amount
				Rate				Maturity				of Debt
Non-recourse project debt:
	Independence notes and bonds:
		Secured bonds payable in semiannual installments commencing June 2003			8.50	%(a)			2007			$	107
		Secured bonds payable in semiannual installments commencing December 2007			9.00	%(a)			2013				409
	Term loan repayable primarily in quarterly installments:
		Batavia			18.00	%			2007				1
Subordinated debt:
		Tracking account loan payable in semiannual installments commencing June 2015			7.00	%(a)			2035				419
Total face amount of debt												$	936
	Unamortized debt discount and premium, net												(100	)
	Long-term debt due within one year												(33	)
Total long-term debt												$	803

---

(a)		In addition to the stated interest rate, an additional 1.97% and 0.99% of interest on the carrying amount of the secured bonds payable is being credited due to debt premiums and 1.63% of interest on the carrying amount of the subordinated debt is being incurred due to the debt discount recorded at the time of the purchase.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Aggregate maturities of Sithe’s debt are as follows:

2004		$	16
2005			34
2006			37
2007			40
2008			44
2009 and thereafter			765
Total minimum payments			936
Net debt discount to be amortized to interest expense			(100	)
Present value of minimum payments		$	836

      Interest-Rate Swaps. In September 2004, Exelon entered into forward-starting interest-rate swaps in the aggregate amount of $160 million to lock in interest rate levels in anticipation of a future financing. The debt issuance that these swaps are hedging was considered probable as of September 30, 2004; therefore, Exelon accounted for these interest-rate swaps as cash-flow hedges. At September 30, 2004, these interest-rate swaps, designated as cash-flow hedges, had an aggregate fair market value of less than $1 million based on the present value difference between the contract and market rates at September 30, 2004. If these derivative instruments had been terminated at September 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to Exelon.

      In 2004, ComEd entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of $240 million. At September 30, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $9 million based on the present value difference between the contract and market rates at September 30, 2004. If these derivative instruments had been terminated at September 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.

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

      Exelon, ComEd, PECO and Generation provide severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each employee’s years of service with Exelon and compensation level. The registrants account for their ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43,” and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

      In conjunction with The Exelon Way, a company-wide effort to define how Exelon will conduct business in years to come, Exelon, ComEd, PECO and Generation have collectively identified 1,850 positions for elimination as of September 30, 2004. Exelon, ComEd, PECO and Generation based their estimates of the number of positions to be eliminated on management’s current plans and ability to determine the appropriate staffing levels to effectively operate the businesses. Exelon, ComEd, PECO and Generation may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be first reasonably estimated.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following tables present, by segment, Exelon’s total salary continuance severance costs for the three and nine months ended September 30, 2004 and 2003. These tables include charges for new positions identified in addition to revised estimates to reflect specific individuals instead of positions previously identified under The Exelon Way.

		Energy																Exelon
Salary Continuance Severance		Delivery				Generation				Enterprises				Corporate				Consolidated
Expense recorded for three months ended September 30, 2004		$	10			$	6			$	—			$	3			$	19
Expense recorded for nine months ended September 30, 2004			14				1				—				8				23

		Energy																Exelon
Salary Continuance Severance		Delivery				Generation				Enterprises				Corporate				Consolidated
Expense recorded for three months ended September 30, 2003		$	50			$	20			$	7			$	10			$	87
Expense recorded for nine months ended September 30, 2003			53				24				7				11				95

      The following tables provide total salary continuance severance costs for ComEd, PECO and Generation for the three and nine months ended September 30, 2004 and 2003.

Salary Continuance Severance		ComEd				PECO				Generation
Expense (income) recorded for three months ended September 30, 2004		$	11			$	(1	)		$	6
Expense recorded for nine months ended September 30, 2004			11				3				1

Salary Continuance Severance		ComEd				PECO				Generation
Expense recorded for three months ended September 30, 2003		$	37			$	13			$	20
Expense recorded for nine months ended September 30, 2003			37				16				24

      The following tables provide a roll forward of the salary continuance severance obligations from January 1, 2003 through September 30, 2004 for Exelon, ComEd, PECO and Generation:

		Exelon
Salary Continuance Obligations		Consolidated				ComEd				PECO				Generation
Balance at January 1, 2003		$	39			$	15			$	—			$	11
Additions			135				61				16				38
Payments			(39	)			(21	)			(2	)			(9	)
Other adjustments			4				—				—				3
Balance at January 1, 2004			139				55				14				43
Additions			23				11				3				1
Payments			(64	)			(21	)			(8	)			(23	)
Other adjustments(a)			(6	)			(3	)			—				—
Balance at September 30, 2004		$	92			$	42			$	9			$	21

45

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

---

(a)		In 2004, Generation increased the reserve for liabilities acquired upon the transfer of the operations of Exelon Energy Company to Generation on January 1, 2004, and reduced the reserve for liabilities associated with Boston Generating, which was sold in May 2004.

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

      Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and Exelon Business Services Company (BSC) employees and certain employees of Enterprises. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen.

      The defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions,” and are disclosed in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits — an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003). The costs of providing benefits under these plans are dependent on historical information, such as employee age, length of service and level of compensation, and the actual rate of return on plan assets, in addition to assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs. The effects of changes in these factors on pension and other postretirement welfare benefit obligations are generally recognized over the expected remaining service life of the employees rather than immediately recognized in the income statement. Exelon uses a December 31 measurement date for the majority of its plans.

      Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans, and Exelon has submitted applications to the IRS for rulings on the tax-qualification of the form of each plan. By letters dated April 21, 2004, the IRS notified Exelon that the rulings on its applications for the traditional and management cash balance plans were delayed pending advice from the IRS’s National Office, pursuant to a previously announced moratorium on rulings with respect to plans involved in so called cash balance “conversions.” On June 1, 2004, the IRS issued a favorable ruling on the union cash balance plan.

      On June 15, 2004, the U.S. Treasury Department announced the withdrawal of its proposed regulations covering cash balance plans in order to provide Congress an opportunity to consider proposed legislation. In addition, various methods used by other employers to accrue and calculate benefits under cash balance plans have been challenged in recent lawsuits. The design of Exelon’s cash balance plans differs in certain material respects from the cash balance plans involved in the cases decided to date, and the courts have not reached uniform decisions on certain issues. As a result, considerable uncertainty remains regarding the application of the Employee Retirement Income Security Act of 1974, the Internal Revenue Code and Federal employment laws to cash balance plans. Exelon does not know how the current uncertainty will be resolved and cannot determine at this time what impact, if any, future developments in this area will have on its pension plans or the funding of its pension obligations.

46

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      During the second quarter of 2004, Exelon early adopted FSP FAS 106-2. See Note 2 — New Accounting Principles for information regarding the adoption of FSP FAS 106-2 and the effect on the net periodic benefit cost of the other postretirement benefits plans included in the tables below.

      During the third quarter of 2004, Exelon announced changes to the benefit provisions of its postretirement welfare benefit plans. The changes will be effective January 1, 2005 and triggered a remeasurement of the plan assets and obligations as of August 1, 2004. The plan change resulted in a reduction in the accumulated postretirement benefit obligation of $106 million and a reduction of projected other postretirement benefit costs in 2004 of $6 million that will be recognized in the third and fourth quarters of 2004.

      The following tables present the components of Exelon’s net periodic benefit costs recognized for the three and nine months ended September 30, 2004 and 2003, including the net periodic benefit costs of AmerGen’s pension and postretirement plans for 2004. These tables reflect an annualized reduction in net periodic postretirement benefit cost of $32 million related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Footnote 2 — New Accounting Principles. The expected long-term rate of return on plan assets used to estimate 2004 pension benefit costs was 9.00%. Prior to the August 1, 2004 remeasurement, the expected long-term rate of return on plan assets used to estimate 2004 other postretirement benefit costs was 8.33%. The expected long-term rate of return on plan assets used for the August 1, 2004 remeasurement of the other postretirement benefit obligation was 8.35%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

											Other
											Postretirement
			Pension Benefits								Benefits
			Three Months								Three Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Service cost			$	31			$	27			$	19			$	18
Interest cost				139				130				38				45
Expected return on assets				(152	)			(143	)			(22	)			(18	)
Amortization of:
	Transition obligation (asset)			(1	)			(7	)			3				3
	Prior service cost			3				9				(22	)			(8	)
	Actuarial loss			22				—				7				12
Curtailment charge				—				11				—				15
Special termination benefits charge				—				—				8				54
Net periodic benefit cost			$	42			$	27			$	31			$	121

47

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

											Other
											Postretirement
			Pension Benefits								Benefits
			Nine Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Service cost			$	97			$	81			$	59			$	52
Interest cost				407				390				127				128
Expected return on assets				(459	)			(435	)			(68	)			(56	)
Amortization of:
	Transition obligation (asset)			(3	)			(9	)			7				8
	Prior service cost			11				17				(60	)			(35	)
	Actuarial loss			52				11				37				36
Curtailment charge				5				11				3				15
Special termination benefits charge				—				—				16				54
Net periodic benefit cost			$	110			$	66			$	121			$	202

      The following table presents the allocation by registrant of Exelon’s pension and post-retirement benefit costs, excluding curtailment and special termination benefits costs, during the three and nine months ended September 30, 2004 and 2003. These amounts include a reduction in net periodic postretirement benefit cost resulting from the adoption of FSP FAS 106-2.

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Pension and Postretirement Benefit Costs		2004				2003				2004				2003
ComEd		$	20			$	20			$	67			$	66
PECO			8				9				25				41
Generation			30				21				89				69

      The following tables present the allocation by registrant of Exelon’s curtailment and special termination benefit charges during the three and nine months ended September 30, 2004 and 2003:

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Curtailment Charges		2004				2003				2004				2003
ComEd		$	—			$	2			$	3			$	2
PECO			—				16				2				16
Generation			—				7				3				7

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Special Termination Benefit Charges		2004				2003				2004				2003
ComEd		$	6			$	20			$	8			$	20
PECO			—				12				2				12
Generation			2				20				4				20

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      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, 2004 and 2003:

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Savings Plan Matching Contributions		2004				2003				2004				2003
Exelon		$	15			$	15			$	43			$	42
ComEd			4				5				12				14
PECO			2				2				5				6
Generation			7				6				20				18

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

	Exelon

      Exelon’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,
			2004				2003				2004				2003
U.S. Federal statutory rate				35.0	%			35.0	%			35.0	%			35.0	%
Increase (decrease) due to:
	Synthetic fuel-producing facilities credit(a)			(6.6	)			—				(6.9	)			—
	Low income housing credit			(0.4	)			1.6				(0.5	)			(1.3	)
	Nuclear decommissioning trust income			0.4				(1.2	)			0.5				1.2
	Amortization of investment tax credit			(0.1	)			1.3				(0.3	)			(1.0	)
	Tax-exempt interest income			(0.3	)			0.8				(0.4	)			(0.7	)
	State income taxes, net of Federal income tax benefit			3.3				13.1				2.9				1.0
	Nontaxable employee benefits			(0.2	)			—				(0.3	)			—
	Other, net			1.5				1.7				0.9				(1.1	)
Effective income tax rate				32.6	%			52.3	%			30.9	%			33.1	%

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(a)		See Note 3 — Acquisitions and Dispositions for further information regarding these investments.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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,
			2004				2003				2004				2003
U.S. Federal statutory rate				35.0	%			35.0	%			35.0	%			35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit			4.8				4.8				4.8				4.8
	Plant basis differences			2.4				—				0.6				—
	Amortization of regulatory asset			0.6				0.6				0.6				0.6
	Amortization of investment tax credit			(0.3	)			(0.3	)			(0.3	)			(0.3	)
	Nontaxable employee benefits			(0.3	)			—				(0.3	)			—
	Other			1.2				(1.6	)			0.3				(0.6	)
Effective income tax rate				43.4	%			38.5	%			40.7	%			39.5	%

	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,
			2004				2003				2004				2003
U.S. Federal statutory rate				35.0	%			35.0	%			35.0	%			35.0	%
Increase (decrease) due to:
	Plant basis differences			1.9				(0.9	)			—				(1.0	)
	State income taxes, net of Federal income tax benefit			(0.2	)			1.7				(0.1	)			1.2
	Amortization of investment tax credit			(0.3	)			(0.3	)			(0.3	)			(0.4	)
	Nontaxable employee benefits			(0.2	)			—				(0.2	)			—
	Other			1.2				(1.0	)			—				(0.2	)
Effective income tax rate				37.4	%			34.5	%			34.4	%			34.6	%

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Generation

      Generation’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,
			2004				2003				2004				2003
U.S. Federal statutory rate				35.0	%			35.0	%			35.0	%			35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit			3.7				4.1				3.6				3.0
	Tax exempt interest income			(0.5	)			0.3				(0.8	)			1.0
	Dividend exclusion			—				—				(0.3	)			—
	Nontaxable employee benefits			(0.2	)			—				(0.3	)			—
	Amortization of investment tax credit			—				0.2				(0.3	)			0.7
	Nuclear decommissioning trust income			0.7				(0.4	)			1.3				(1.7	)
	Other			(0.4	)			0.3				—				0.1
Effective income tax rate				38.3	%			39.5	%			38.2	%			38.1	%

13.	Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

      Please refer to Exelon Corporation’s 2003 Form 10-K for a full discussion on the accounting for nuclear decommissioning and the fair value of financial assets and liabilities.

	Asset Retirement Obligations

      SFAS No. 143 provides accounting guidance for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Liabilities for SFAS No. 143 asset retirement obligations (AROs) have been recorded at Generation in connection with its obligation to decommission its nuclear power plants as well as legal obligations associated with the closing of its fossil power plants. Based on the extended license lives of the nuclear plants, decommissioning expenditures are expected to occur primarily during the period 2029 through 2056. Exelon, through its regulated subsidiary utility companies, ComEd and PECO, currently recovers costs for decommissioning Generation’s nuclear generating stations, excluding the three AmerGen plants, through regulated rates. The amounts recovered from customers are deposited into trust accounts and invested for funding the future decommissioning costs of the nuclear generating stations.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following table presents a rollforward of the ARO reflected on the Exelon and Generation Consolidated Balance Sheets from January 1, 2003 to September 30, 2004:

		Generation				Exelon
Asset retirement obligation at January 1, 2003		$	2,363			$	2,366
Consolidation of AmerGen			487				487
Accretion expense			160				161
Expenditures to decommission retired plants			(14	)			(14	)
Reclassification of Thermal ARO as held for sale(a)			—				(3	)
Asset retirement obligation at December 31, 2003			2,996				2,997
Net increase resulting from updates to estimated future cash flows			325				325
Accretion expense for the nine months ended September 30, 2004			154				154
Additional liabilities incurred(b)			6				6
Expenditures to decommission retired plants			(9	)			(9	)
Asset retirement obligation at September 30, 2004		$	3,472			$	3,473

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(a)		The ARO of Thermal was removed from the balance sheet upon Thermal’s sale in the second quarter of 2004.
(b)		Additional liabilities incurred are primarily due to the consolidation of Sithe.

     Exelon updates its ARO on a periodic basis. In September 2004, Generation recorded a $325 million net increase to the ARO resulting from updates to estimated future expected nuclear decommissioning cash flows comprised of a $374 million increase in the estimated ARO for certain nuclear units, offset by a $49 million decrease in the estimated ARO for another unit. Increases in the ARO resulted in the establishment of a corresponding Asset Retirement Cost (ARC) of $374 million, including approximately $36 million related to retired units. The ARC associated with three of the units was immediately impaired through depreciation expense as it was associated with retired nuclear units that do not have any remaining useful life. For the unit with the estimated $49 million ARO decrease, and pursuant to FAS 143, decreases in AROs are first offset by any existing related ARCs for those units and, to the extent there is no ARC, the amounts are included in operating income. However, currently there is no impact to net income for the decommissioning of the former ComEd and PECO units and, as such, both the $36 million impairment charge and the $49 million ARO decrease were equally offset by a charge of $13 million in operating income.

      The net increase in the ARO for the former ComEd units, the former PECO units and the AmerGen units during the third quarter of 2004 was $121 million, $147 million and $57 million, respectively. The ARO balances at September 30, 2004 for the former ComEd units, the former PECO units and the AmerGen units were approximately $1.875 billion, $1.015 billion and $575 million, respectively.

      The increase to the ARO recorded in the third quarter of 2004 resulted primarily from updated decommissioning cost studies provided by third-party providers and changes in cost escalation factors used to estimate future undiscounted costs. The adjustment did not have a significant impact on the Consolidated Statements of Income and Comprehensive Income of Exelon or Generation.

      Generation expects additional cost estimate updates from third-party providers in the fourth quarter of 2004. The change to the ARO in the fourth quarter cannot be reasonably estimated at this time.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Nuclear Decommissioning Trust Fund Investments

      At December 31, 2003, Exelon had gross unrealized gains of $394 million and gross unrealized losses of $300 million related to the nuclear decommissioning trust fund investments. With the exception of the portion of these amounts primarily related to AmerGen, as a result of its regulatory arrangements for decommissioning costs, approximately $62 million of these net gains were recorded as an increase to regulatory liabilities. At September 30, 2004, prior to its evaluation for other-than-temporary impairments, Exelon had gross unrealized gains of $480 million and gross unrealized losses of $345 million. The gross unrealized losses were comprised of $314 million related to trust accounts for the decommissioning of the former ComEd and PECO plants and $31 million primarily related to the trust accounts for the decommissioning of the AmerGen plants.

      Exelon has historically evaluated the decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of its securities in unrealized loss positions in comparison to related market indices. As of September 30, 2004, Exelon 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 securities and considerations of Exelon’s ability and intent to hold the investments until the recovery of their cost basis. This determination resulted in a $7 million impairment charge recorded in other income and deductions associated with the trust funds for the decommissioning of the AmerGen plants. Also, Exelon realized $260 million of the previously unrealized losses of $314 million associated with the trust investments for the decommissioning of the former ComEd and PECO plants. As both realized and unrealized losses are included as a reduction in the fair value of the investments and in the fair value of the regulatory liability, this realization of these losses associated with the former ComEd and PECO plants had no impact on Exelon’s or Generation’s results of operations or financial position.

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

	Stock Split

      On January 27, 2004, the Board of Directors of Exelon approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The authorized common stock was increased from 600,000,000 shares with no par value to 1,200,000,000 shares with no par value. The share and per-share amounts included in Exelon’s consolidated financial statements and combined notes to consolidated financial statements have been adjusted for all periods presented to reflect the stock split.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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 computation 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 Ended								Nine Months Ended
			September 30,								September 30,
			2004				2003				2004				2003
Income before cumulative effect of changes in accounting principles			$	577			$	(102	)		$	1,478			$	519
Cumulative effect of changes in accounting principles				(9	)			—				23				112
Net income (loss)			$	568			$	(102	)		$	1,501			$	631
Average common shares outstanding — basic				661				652				660				650
Assumed exercise of stock options				8				—				8				5
Average common shares outstanding — diluted				669				652				668				655
Earnings (loss) per average common share — Basic:
	Income before cumulative effect of changes in accounting principles		$	0.87			$	(0.16	)		$	2.23			$	0.80
	Cumulative effect of changes in accounting principles			(0.01	)			—				0.04				0.17
	Net income (loss)		$	0.86			$	(0.16	)		$	2.27			$	0.97
Earnings (loss) per average common share — Diluted:
	Income before cumulative effect of changes in accounting principles		$	0.86			$	(0.16	)		$	2.21			$	0.79
	Cumulative effect of changes in accounting principles			(0.01	)			—				0.04				0.17
	Net income (loss)		$	0.85			$	(0.16	)		$	2.25			$	0.96

      The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 30 million for the three months ended September 30, 2003 and 50 thousand and 10 million for the nine months ended September 30, 2004 and 2003, respectively. There were no stock options excluded for the three months ended September 30, 2004.

	Share Repurchase Program

      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 value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after

54

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The share repurchase program has no specified limit on the number of shares that may be repurchased and no specified termination date. Any shares repurchased are held as treasury shares unless cancelled or reissued at the discretion of Exelon’s management. Treasury shares are recorded at cost. For the nine months ended September 30, 2004, 2.3 million shares of common stock were purchased under the share repurchase program for $75 million.

	Shareholders’ Equity

      The following table summarizes the changes in shareholders’ equity for the nine months ended September 30, 2004:

																		Accumulated
																		Other
																		Comprehensive				Total
		Issued				Common				Treasury				Retained				Income				Shareholders’
Dollars in millions, shares in thousands		Shares				Stock				Stock				Earnings				(Loss)				Equity
Balance, December 31, 2003			656,366			$	7,292			$	—			$	2,320			$	(1,109	)		$	8,503
Net income							—				—				1,501				—				1,501
Long-term incentive plan activity			8,268				233				—				—				—				233
Employee stock purchase plan issuances			243				7				—				—				—				7
Common stock purchases			—				—				(75	)			—				—				(75	)
Common stock dividends declared			—				—				—				(565	)			—				(565	)
Adjustments to accumulated other comprehensive income due to the consolidation of Sithe			—				—				—				—				(6	)			(6	)
Other comprehensive loss			—				—				—				—				(52	)			(52	)
Balance, September 30, 2004			664,877			$	7,532			$	(75	)		$	3,256			$	(1,167	)		$	9,546

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

      For information regarding capital commitments and nuclear decommissioning at December 31, 2003, see the Commitments and Contingencies and Nuclear Decommissioning and Spent Fuel Storage notes in the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation in the 2003 Form 10-K.

	Energy Commitments

      At September 30, 2004, Generation’s long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from unaffiliated utilities and others, including the Midwest Generation contract, did not change significantly from December 31, 2003, except for the following:

	•	Sithe has power-only sales commitments of $42 million, transmission rights of $22 million and minimum fuel purchase commitments of $109 million.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Commercial Commitments

      Exelon, ComEd, PECO and Generation’s commercial commitments as of September 30, 2004, representing commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payments on behalf of other parties and financing arrangements to secure obligations, did not change significantly from December 31, 2003, except for the following:

	•	Generation acquired a $50 million letter of credit to support the contractual obligations of Sithe and its subsidiaries and issued a $45 million of letter of credit for Power Team to cover collateral calls that had previously been met with cash collateral. Excluding the above items, Exelon’s net letters of credit decreased $24 million for the nine months ending September 30, 2004.
	•	Mystic Development LLC (Mystic), a former affiliate of Exelon New England has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN No. 45, approximately $17 million is included as a liability within the Consolidated Balance Sheets of Exelon and Generation as of September 30, 2004 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee.
	•	On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call is subject to state and Federal regulatory approvals. See Note 4 — Sithe for additional information.
	•	In connection with the transfer of Exelon Energy Company to Generation effective January 1, 2004, Generation acquired $162 million in energy marketing contract guarantees. This transfer had no effect on the guarantees of Exelon.

	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. Exelon has identified 69 sites where former MGP activities have or may have resulted in actual site contamination. Of these 69 sites, the Illinois Environmental Protection Agency has approved the clean up of 4 sites and the Pennsylvania Department of Environmental Protection has approved the clean up of 8 sites. Pursuant to a Pennsylvania Public Utility Commission (PUC) order, PECO is currently recovering a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset (see Note 16 — Supplemental Financial Information). As of

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2004 and December 31, 2003, Exelon, ComEd, PECO and Generation had accrued the following amounts for environmental liabilities:

		Total
		Environmental				Portion of Total
		Investigation and				Related
		Remediation				to MGP Investigation
September 30, 2004		Reserve				and Remediation(a)
Exelon		$	120			$	98
ComEd			62				56
PECO			48				42
Generation			10				—

---

(a)		Discounted.

		Total
		Environmental				Portion of Total
		Investigation and				Related
		Remediation				to MGP Investigation
December 31, 2003		Reserve				and Remediation(a)
Exelon		$	129			$	105
ComEd			69				64
PECO			50				41
Generation			10				—

---

(a)		Discounted.

     Exelon, ComEd, PECO and Generation 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.

	Spent Fuel Storage

      During the third quarter of 2004, Exelon and the U.S. Department of Justice, in close consultation with the Department of Energy (DOE), reached a settlement under which the government will reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfillment of its obligations. Under the agreement, Generation received $80 million immediately in gross reimbursements for storage costs already incurred ($53 million net after considering amounts due from Generation to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel. As of September 30, 2004, the amount of spent fuel storage costs for which reimbursement will be requested in mid-2005 from the DOE under the settlement agreement is $26 million net, which is recorded within accounts receivable, other. This amount is comprised of $12 million which has been recorded as a reduction to operating and maintenance expense and $8 million which has been recorded as a reduction to capital expenditures, both recorded during the three months ended September 30, 2004. The remaining $6 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Litigation

	ComEd

      Retail Rate Law. In 1996, three developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. ComEd and Illinois each appealed the ruling. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. On October 6, 2004, the Supreme Court declined to hear the final appeal.

	PECO and Generation

      Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on 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 Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through its wholly owned subsidiary AmerGen, Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).

      PECO and Generation believe their reserve balances for exposures associated with the real estate taxes as of September 30, 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies.” The ultimate outcome of such matters, however, could result in additional unfavorable or favorable adjustments to the consolidated financial statements of Exelon, PECO and Generation and such adjustments could be material.

	Generation

      Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary Cotter Corporation (Cotter) seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. Several of these actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs of a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. See Note 19 — Subsequent Events for information regarding the settlement of this litigation.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      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 these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.

      The U.S. Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. 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, which will determine the remedy. The estimated costs of the anticipated remediation strategy for the site may range up to $22 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.

      Raytheon and Mitsubishi Litigation. In connection with the February 2004 settlement among Exelon, Generation and the lenders under the Boston Generating Credit Facility more fully described in Note 3 — Acquisitions and Dispositions, Exelon, Generation, and Raytheon, as the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities. Under the global settlement, Generation agreed to pay approximately $31 million to Raytheon and approximately $1 million to Boston Generating. Raytheon released Exelon, Generation, their affiliates and the lenders from construction claims related to the projects. Raytheon also resolved all of the pending Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) claims relating to work performed on the projects prior to the settlement, and indemnified Exelon, Generation, their affiliates and the lenders from certain subcontractor claims relating to the projects. In return, Exelon, Generation, their affiliates and the lenders released all of their claims against Raytheon. All litigation by and between Raytheon, MHI, MHIA and the project companies relating to the projects has been dismissed.

      Oyster Creek. On April 7, 2004, AmerGen entered into settlements with the State of New Jersey relating to an environmental incident on September 23, 2002 at Oyster Creek. The incident resulted in a fishkill from heated water discharged from the plant. The State alleged that the plant had violated its water discharge permit. The settlements with the State of New Jersey settled all claims without any admission of liability for payments aggregating $1 million.

	Exelon, ComEd, PECO and Generation

      Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are 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 matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on their respective financial condition, results of operations or cash flows.

	Credit Contingencies

      Dynegy. Generation is counterparty to Dynegy, Inc. (Dynegy) in various energy transactions. The credit ratings of Dynegy are below investment grade. As of September 30, 2004, Generation has credit risk

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

associated with Dynegy through Generation’s investment in Sithe. Sithe is a 100% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of March 31, 2004, Generation consolidated the assets and liabilities of Sithe in accordance with the provisions of FIN No. 46-R. As a result, Generation recorded an asset of $127 million on its Consolidated Balance Sheets related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133, “Accounting for Derivatives and Hedging Activities.” If Dynegy were unable to fulfill the terms of the financial swap agreement, Generation would be required to impair the related asset. Exelon estimates, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of its net income by approximately $23 million. See Note 4 — Sithe for information regarding Generation’s exercise of a call option to acquire the remaining 50% of Sithe.

      In addition to the asset impairment, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur an impairment of the intangible asset associated with the Independence plant tolling agreement. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of up to $50 million. In the event of a sale of Generation’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $84 million, which would represent an after-tax loss of up to $50 million.

      Generation previously disclosed that the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company (Illinois Power), a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On September 30, 2004, Dynegy sold Illinois Power to a third party, which reduced Generation’s credit risk associated with Dynegy.

	Income Tax Refund Claims

      ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultant of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds to be recovered from the IRS, if any. The ultimate net cash outflow to ComEd and PECO related to all the agreements will either be positive or neutral depending upon the outcome of the refund claims 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. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (Merger), would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd and PECO cannot predict the timing of the final resolution of the refund claims.

      During the second quarter of 2004, the IRS granted preliminary approval for one of ComEd’s refund claims. As such, ComEd believes that it is probable that a fee will ultimately be paid to the tax consultant. Therefore, ComEd has recorded an expense of $5 million (pretax), which resulted in a decrease to the prepayment from $11 million to $6 million. The charge represents an estimate of the fee to the tax consultant which may be adjusted upward or downward depending on the IRS’ final calculation of the tax and interest benefit. ComEd has not reflected the tax benefit associated with the refund claim pending final approval of the IRS. However, as described above, the net income statement impact for ComEd is not anticipated to be material.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Jointly Owned Electric Utility Plant

      On January 28, 2004, the NRC issued a letter requesting Public Service Enterprise Group (PSEG) to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004, and had independent assessments of the work environment at the facility performed. Assessment results were provided to the NRC in May 2004. The assessments concluded that Salem was safe for continued operation, but also identified issues that needed to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program, and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. PSEG will provide the NRC a report of its progress and discuss the progress of its actions to resolve identified issues at public meetings on December 2, 2004 and in 2005. PSEG will publish metrics to demonstrate performance commencing in the fourth quarter of 2004.

      In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed National Pollutant Discharge Elimination System permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the agency grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit would result in material costs of compliance to the owners of the facility.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

16.	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 Income and Comprehensive Income of Exelon, ComEd, PECO and Generation for the three and nine months ended September 30, 2004 and 2003:

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Exelon		2004				2003				2004				2003
Investment income		$	12			$	7			$	38			$	27
Net loss on extinguishment of long-term debt			(106	)			—				(106	)			—
Gain on sale of Boston Generating(a)			—				—				85				—
Gain (loss) on disposition of other assets and investments, net			(2	)			1				86				2
Impairment of investment in Sithe(b)			—				(55	)			—				(255	)
Write-down of other impaired assets and investments			(7	)			—				(7	)			(42	)
AFUDC, equity			1				5				3				11
Reversal of reserve for potential plant disallowance			—				—				—				12
Other			(5	)			(2	)			22				19
Other, net		$	(107	)		$	(44	)		$	121			$	(226	)

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(a)		See Note 3 — Acquisitions and Dispositions for further information regarding Generation’s sale of Boston Generating.
(b)		See Note 4 — Sithe for further information regarding impairments recorded related to Generation’s investment in Sithe.

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
ComEd		2004				2003				2004				2003
Investment income		$	1			$	2			$	2			$	4
Gain (loss) on disposition of assets and investments, net			(1	)			1				1				2
AFUDC, equity			—				5				2				11
Reversal of reserve for potential plant disallowance			—				—				—				12
Other			(1	)			1				1				(1	)
Other, net		$	(1	)		$	9			$	6			$	28

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
PECO		2004				2003				2004				2003
Investment income		$	—			$	3			$	3			$	8
Gain on disposition of assets and investments, net			2				—				4				—
AFUDC, equity			1				—				1				—
Interest associated with Federal income taxes			—				(14	)			—				(14	)
Other			—				1				—				6
Other, net		$	3			$	(10	)		$	8			$	—

		Three Months								Nine Months
		Ended								Ended
		September 30,								September 30,
Generation		2004				2003				2004				2003
Decommissioning trust funds(a)		$	1			$	—			$	—			$	10
Decommissioning trust funds — AmerGen(a)			9				—				30				—
Gain on sale of Boston Generating(b)			—				—				85				—
Impairment of investment in Sithe(c)			—				(55	)			—				(255	)
Other			(5	)			2				14				7
Other, net		$	5			$	(53	)		$	129			$	(238	)

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(a)		Includes investment income and realized gains/(losses).
(b)		See Note 3 — Acquisitions and Dispositions for further information regarding Generation’s sale of Boston Generating.
(c)		See Note 4 — Sithe for further information regarding impairments recorded related to Generation’s investment in Sithe.

	Supplemental Balance Sheet Information

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

		September 30,				December 31,
ComEd		2004				2003
Regulatory Assets (Liabilities)
Nuclear decommissioning		$	(1,259	)		$	(1,183	)
Removal costs			(1,002	)			(973	)
Recoverable transition costs			97				131
Reacquired debt costs and interest-rate swap settlements			125				172
Deferred income taxes			3				(61	)
Other			27				23
Total		$	(2,009	)		$	(1,891	)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		September 30,				December 31,
PECO		2004				2003
Regulatory Assets (Liabilities)
Competitive transition charge		$	4,021			$	4,303
Deferred income taxes			766				762
Non-pension postretirement benefits			53				58
Reacquired debt costs			43				49
MGP regulatory asset (see Note 15 — Commitments and Contingencies)			31				34
U.S. Department of Energy facility decommissioning			21				26
Nuclear decommissioning			(15	)			(12	)
Other			11				6
Long-term regulatory assets			4,931				5,226
Deferred energy costs (current asset)			29				81
Total		$	4,960			$	5,307

      The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of September 30, 2004 and December 31, 2003:

September 30, 2004			Exelon				ComEd				PECO				Generation
Property, plant and equipment:
	Accumulated depreciation		$	6,732			$	940			$	2,131			$	3,553
Accounts receivable:
	Allowance for uncollectible accounts			97				16				58				18

December 31, 2003			Exelon				ComEd				PECO				Generation
Property, plant and equipment:
	Accumulated depreciation		$	6,948			$	771			$	2,048			$	4,025
Accounts receivable:
	Allowance for uncollectible accounts			110				16				72				14

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

      Exelon operates in three business segments: Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon evaluates the performance of its business segments on the basis of net income.

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended September 30, 2004 and 2003

      Exelon’s segment information for the three months ended September 30, 2004 and 2003 is as follows:

														Corporate and
		Energy												Intersegment
		Delivery				Generation				Enterprises				Eliminations				Consolidated
Total revenues(a):
2004		$	2,844			$	2,253			$	15			$	(1,247	)		$	3,865
2003			2,886				2,630	(b)			291	(b)			(1,366	)			4,441
Intersegment revenues:
2004		$	3			$	1,244			$	—			$	(1,247	)		$	—
2003			23				1,304	(b)			38	(b)			(1,365	)			—
Income (loss) before income taxes, minority interest and cumulative effect of a change in accounting principle:
2004		$	440			$	517			$	(17	)		$	(82	)		$	858
2003			479				(713	)(b)			31	(b)			(11	)			(214	)
Income taxes:
2004		$	178			$	198			$	(6	)		$	(90	)		$	280
2003			176				(282	)(b)			12	(b)			(18	)			(112	)
Cumulative effect of a change in accounting principle:
2004		$	—			$	—			$	(9	)		$	—			$	(9	)
2003			—				—				—				—				—
Net income (loss):
2004		$	262			$	319			$	(20	)		$	7			$	568
2003			303				(431	)(b)			19	(b)			7				(102	)

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(a)		$55 million and $65 million in utility taxes are included in the revenues and expenses for the three months ended September 30, 2004 and 2003, respectively, for ComEd. $59 million and $61 million in utility taxes are included in the revenues and expenses for the three months ended September 30, 2004 and 2003, respectively, for PECO.
(b)		Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for the three months ended September 30, 2003 included in the table above has been adjusted to reflect Exelon Energy Company as part of the Generation segment. For the three months ended September 30, 2003, Exelon Energy Company reported the following:

Total revenues		$	146
Loss from continuing operations before income taxes		$	(5	)
Income tax benefit		$	(2	)
Net loss		$	(3	)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Nine Months Ended September 30, 2004 and 2003, September 30, 2004 and December 31, 2003

      Exelon’s segment information for the nine months ended September 30, 2004 and 2003 and at September 30, 2004 and December 31, 2003 is as follows:

														Corporate and
		Energy												Intersegment
		Delivery				Generation				Enterprises				Eliminations				Consolidated
Total revenues(a):
2004		$	7,853			$	6,153			$	148			$	(3,017	)		$	11,137
2003			7,850				6,797	(b)			808	(b)			(3,219	)			12,236
Intersegment revenues:
2004		$	24			$	2,994			$	—			$	(3,018	)		$	—
2003			58				3,095	(b)			69	(b)			(3,222	)			—
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles:
2004		$	1,426			$	900			$	9			$	(211	)		$	2,124
2003			1,478				(566	)(b)			(79	)(b)			(53	)			780
Income taxes:
2004		$	546			$	343			$	9			$	(242	)		$	656
2003			558				(217	)(b)			(29	)(b)			(54	)			258
Cumulative effect of changes in accounting principles:
2004		$	—			$	32			$	(9	)		$	—			$	23
2003			5				108				(1	)			—				112
Net income (loss):
2004		$	880			$	599			$	(9	)		$	31			$	1,501
2003			925				(243	)(b)			(51	)(b)			—				631
Total assets:
September 30, 2004		$	27,794			$	15,484	(c)		$	278			$	(1,497	)		$	42,059
December 31, 2003			28,369				14,765	(b)			727	(b)			(1,925	)			41,936

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(a)		$174 million and $178 million in utility taxes are included in the revenues and expenses for the nine months ended September 30, 2004 and 2003, respectively, for ComEd. $160 million and $159 million in utility taxes are included in the revenues and expenses for the nine months ended September 30, 2004 and 2003, respectively, for PECO.
(b)		Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for the nine months ended September 30, 2003 and as of December 31, 2003 included in the table above has been adjusted to reflect Exelon Energy Company as part of the Generation segment.
(c)		Includes $1,324 million of Sithe consolidated assets under the provisions of FIN No. 46-R. See Note 4 — Sithe for further information regarding the consolidation of Sithe.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Exelon Energy Company’s total assets as of December 31, 2003 were $134 million and for the nine months ended September 30, 2003, Exelon Energy Company reported the following:

Total revenues		$	651
Loss before income taxes		$	(20	)
Income tax benefit		$	(8	)
Net loss		$	(12	)

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

	Exelon and ComEd

      Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, LLC and ComEd Transitional Funding Trust were deconsolidated from the financial statements of Exelon and ComEd in conjunction with the adoption of FIN No. 46-R. In accordance with FIN No. 46-R, prior periods were not restated

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

			Three
			Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Interest expense to affiliates
	ComEd Transitional Funding Trust		$	21			$	—			$	65			$	—
	ComEd Financing II			3				—				10				—
	ComEd Financing III			3				—				10				—
Equity in losses from unconsolidated affiliates
	ComEd Funding LLC			(4	)			—				(13	)			—

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			September 30,				December 31,
			2004				2003
Receivables from affiliates (current)
	ComEd Transitional Funding Trust		$	14			$	9
Investment in affiliates
	ComEd Funding, LLC			43				56
	ComEd Financing II			10				11
	ComEd Financing III			6				6
Receivable from affiliates (noncurrent)
	ComEd Transitional Funding Trust			10				9
Payables to affiliates (current)
	ComEd Financing II			3				6
	ComEd Financing III			—				4
Long-term debt to affiliates (including due within one year)
	ComEd Transitional Funding Trust			1,415				1,676
	ComEd Financing II			155				155
	ComEd Financing III			206				206

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

			Three Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Operating revenues from affiliates
	Generation(a)		$	—			$	16			$	16			$	42
	Enterprises(a)			—				4				1				7
Purchased power from affiliate
	PPA with Generation(b)			827				885				1,870				1,984
Operations & maintenance from affiliates
	BSC(c)			46				30				136				76
	Enterprises(d,e)			—				8				—				14
Interest income from affiliates
	UII(f)			5				5				13				17
	Exelon intercompany money pool(j)			1				1				2				2
	Other			—				—				1				1
Capitalized costs
	BSC(c)			17				3				45				11
	Enterprises(e)			—				10				—				21
Cash dividends paid to parent				112				94				320				305

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			September 30,				December 31,
			2004				2003
Receivables from affiliates (current)
	UII(f)		$	4			$	3
	PECO(h)			—				6
	Exelon intercompany money pool(j)			—				405
	Other			1				5
Receivables from affiliates (noncurrent)
	UII(f)			635				1,071
	Generation(k)			1,259				1,183
	Other			2				8
Payables to affiliates (current)
	Generation decommissioning(g)			11				11
	Generation(a,b)			188				171
	Exelon intercompany money pool(j)			17				—
	BSC(c)			20				13
	Other			—				2
Payables to affiliates (noncurrent)
	Generation decommissioning(g)			22				22
	Other			6				6
Shareholders’ equity — receivable from parent(i)				156				250

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(a)		ComEd provides electric and ancillary services to Generation. ComEd provided electric and ancillary services to certain Enterprises companies which were sold in 2004. Prior to joining PJM on May 1, 2004, ComEd also provided transmission services to Generation and Enterprises.
(b)		Effective January 1, 2001, ComEd entered into a full-requirements purchase power agreement (PPA) with Generation.
(c)		ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. Additionally in 2004, due to the centralization of certain functions, certain employees were transferred from ComEd to BSC. As a result, ComEd now receives additional services from BSC including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. A portion of such services, provided at cost including applicable overhead, is capitalized.
(d)		ComEd had contracted with an Enterprises company to provide energy conservation services to ComEd customers. Certain Enterprises companies were sold in 2004.
(e)		ComEd received substation and transmission engineering and construction services under contracts with InfraSource, Inc. (InfraSource). A portion of such services is capitalized. Exelon sold InfraSource in September 2003.
(f)		ComEd has a note and interest receivable with a variable rate of the one month forward LIBOR rate plus 50 basis points from Unicom Investments Inc. (UII) relating to ComEd’s December 1999 fossil plant sale. This note matures in December 2011.
(g)		ComEd has a short-term and long-term payable to Generation, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation.
(h)		In 2003, ComEd provided hurricane restoration assistance to PECO.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(i)		ComEd has a non-interest bearing receivable from Exelon related to a corporate restructuring in 2001. The receivable is expected to be settled over the years 2004 through 2008.
(j)		ComEd participates in Exelon’s intercompany money pool. ComEd earns interest on its investment in and pays interest on its borrowings from the money pool at a market rate of interest.
(k)		ComEd has a long-term receivable from Generation related to a regulatory liability as a result of the adoption of SFAS No. 143.

	Exelon and PECO

      Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of Exelon and PECO in conjunction with the adoption of FIN No. 46. Additionally, effective December 31, 2003, PECO Trust III and the PETT were deconsolidated from the financial statements of Exelon and PECO in conjunction with the adoption of FIN No. 46-R. In accordance with FIN No. 46-R, prior periods were not restated.

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

			Three Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Operating revenues from affiliate
	PETT(a)		$	2			$	—			$	7			$	—
Interest expense to affiliates
	PETT			58				—				178				—
	PECO Trust III			2				—				5				—
	PECO Trust IV			1				2				4				2

			September 30,				December 31,
			2004				2003
Investment in affiliates
	PETT		$	88			$	104
	PECO Energy Capital Corp			16				16
	PECO Trust IV			4				3
Receivables from affiliates (non-current)
	PECO Trust IV			—				1
Payables to affiliates
	PECO Trust III			12				10
	PECO Trust IV			2				—
	PECO Energy Capital Corp			—				1
Long-term debt to affiliates (including due within one year)
	PETT			3,563				3,849
	PECO Trust III			81				81
	PECO Trust IV			103				103

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			Three Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Operating revenues from affiliate
	Generation(a)		$	3			$	3			$	7			$	8
	Other			—				—				—				1
Purchased power from affiliate
	Generation(b)			409				421				1,108				1,101
Fuel from affiliate
	Generation(c)			7				—				14				—
Operating and maintenance from affiliates
	BSC(d)			26				14				77				36
	Enterprises(e)			—				—				—				3
Capitalized costs
	BSC(d)			6				1				15				6
	Enterprises(e)			—				10				—				23
Cash dividends paid to parent				96				79				276				244

			September 30,				December 31,
			2004				2003
Receivable from affiliate (current)
	Exelon intercompany money pool(f)		$	26			$	—
Receivable from affiliate (non-current)
	Generation decommissioning(g)			15				12
Payables to affiliates (current)
	Generation(b)			127				115
	BSC(d)			20				15
	ComEd(h)			—				6
	Other			—				3
Shareholder’s equity — receivable from parent(i)				1,518				1,623

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(a)		PECO provides energy to Generation for Generation’s own use.
(b)		Effective January 1, 2001, PECO entered into a full-requirements PPA with Generation.
(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 and supply management services. Additionally in 2004, due to the centralization of certain functions, certain employees were transferred from PECO to BSC. As a result, PECO now receives additional services from BSC, including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. Such services are provided at cost, including applicable overhead. Some of these costs are capitalized.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(e)		Prior to 2004, PECO received services from Enterprises for construction, which were capitalized, and the deployment of automated meter reading technology, which were expensed.
(f)		PECO participates in Exelon’s intercompany money pool. PECO earns interest on its investment in the money pool at a market rate of interest.
(g)		PECO has a long-term receivable from Generation related to a regulatory liability as a result of the adoption of SFAS No. 143.
(h)		In 2003, PECO received assistance from ComEd workers during Hurricane Isabel.
(i)		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 2004 through 2010.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Exelon and Generation

      The financial statements of Exelon and Generation include related-party transactions with unconsolidated affiliates as presented in the tables below. Generation accounted for its investment in AmerGen as an equity method investment prior to the acquisition of British Energy’s 50% interest in December 2003 and its investment in Sithe as an equity method investment prior to its consolidation as of March 31, 2004. Additionally, effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation.

			Three Months								Nine Months
			Ended								Ended
			September 30,								September 30,
			2004				2003				2004				2003
Operating revenues from affiliates
	ComEd(a)		$	827			$	885			$	1,870			$	1,984
	PECO(a)			416				421				1,122				1,101
	Exelon Energy Company(b)			—				51				—				161
	BSC			1				—				2				—
Purchased power from affiliates
	AmerGen(c)			—				133				—				310
	ComEd(a)			(2	)			11				10				31
	PECO			1				—				1				—
	Exelon Energy Company(b)			—				—				—				9
Operating and maintenance from affiliates
	Sithe(d)			—				—				—				5
	ComEd(a)			2				5				6				11
	PECO(a)			2				3				6				8
	BSC(e)			62				46				188				117
Interest expense to affiliates
	Sithe(d)			—				2				—				7
	Exelo(f)			1				—				1				2
	Exelon intercompany money pool(f)			—				1				2				2
Services provided to affiliates
	AmerGen(c)			—				50				—				85
Cash distribution paid to member				61				71				170				116

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			September 30,				December 31,
			2004				2003
Receivables from affiliates
	ComEd(a)		$	188			$	171
	ComEd decommissioning(g)			11				11
	PECO(a)			127				115
	BSC(e)			—				3
	Exelon Energy Company(b)			—				18
	Sithe(d)			—				3
	Other			8				8
Note receivable from affiliate
	Note receivable from Sithe(d)			—				92
	Exelon intercompany money pool(f)			17				—
	Other			1				—
Long-term receivable from affiliate
	ComEd decommissioning(g)			22				22
Payables to affiliates
	Exelon(f)			—				1
	BSC(e)			28				—
	Other			3				—
Payables to affiliates (non-current)
	ComEd decommissioning(h)			1,259				1,183
	PECO decommissioning(h)			15				12
Notes payable to affiliates
	Exelon(f)			—				115
	Exelon intercompany money pool(f)			—				301
	Sithe(d)			—				90

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(a)		Effective January 1, 2001, Generation entered into full-requirements PPAs with ComEd and PECO. Generation purchases electric and ancillary services from ComEd and buys power from PECO for Generation’s own use. In order to facilitate payment processing, ComEd processes certain invoice payments on behalf of Generation. Prior to joining PJM on May 1, 2004, ComEd also provided transmission services to Generation.
(b)		Generation sells power to Exelon Energy Company. Prior to May 1, 2004, Generation purchased excess power from Exelon Energy Company. Prior to the transfer of Exelon Energy Company’s assets to Generation from Enterprises effective January 1, 2004, Exelon Energy Company was an intercompany affiliate of Generation.
(c)		Prior to Generation’s purchase of British Energy’s 50% interest in AmerGen in December 2003, AmerGen was an unconsolidated affiliate of Exelon and Generation and was considered to be a related party of Exelon and Generation. Generation entered into PPAs dated June 26, 2003, December 18, 2001 and November 22, 1999 with AmerGen. Under the 2003 PPA, Generation agreed to purchase from AmerGen all the energy from Oyster Creek through April 9, 2009. Under the 2001 PPA, Generation agreed to purchase from AmerGen all the energy from TMI from January 1, 2002 through December 31, 2014. Under the 1999 PPA, Generation agreed to purchase from AmerGen all of the residual energy from Clinton through December 31, 2004. Currently, the residual output is approximately 31% of the total output of Clinton. Under a service agreement dated March 1, 1999, Generation provides AmerGen

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		with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost.
(d)		Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services at cost. In December 2003, Sithe received letter of credit proceeds of $3 million, which Generation was billed on behalf of Sithe. Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a note to Sithe which was subsequently modified and increased to $536 million. During 2003, Generation repaid $446 million of this note. In the first quarter of 2004, Generation repaid $27 million prior to consolidation of Sithe in accordance with the provisions of FIN No. 46-R. The balance of the note is to be paid on the earlier of December 1, 2004, certain Sithe liquidity requirements, or upon a change of control of Generation. The note bears interest at the rate equal to LIBOR plus 0.875%. In connection with a series of transactions in November 2003 that restructured the ownership of Sithe (see Note 4 — Sithe for additional information), Generation received a $92 million note receivable from EXRES SHC, Inc., which holds the common stock of Sithe. Generation owns 50% of EXRES SHC, Inc and consolidated its investment pursuant to FIN No. 46-R effective March 31, 2004. Prior to the consolidation of Sithe in connection with FIN No. 46-R, Sithe was an unconsolidated affiliate of Exelon and Generation and was considered to be a related party of Exelon and Generation.
(e)		Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. Such services are provided at cost, including applicable overhead. Some third party reimbursements due Generation are recovered through BSC. Additionally, in 2004, due to the centralization of certain functions, certain employees were transferred from Generation to BSC. As a result, Generation now receives additional services from BSC including for inventory and IT support and management of other support services.
(f)		Represents the outstanding balance of amounts invested in or borrowed under the intercompany money pool and other short-term obligations payable to Exelon. In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.
(g)		Generation has a short-term and a long-term receivable from ComEd, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation resulting from the 2001 corporate restructuring.
(h)		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 ratepayers.

19.	Subsequent Events (Exelon, ComEd, PECO and Generation)

      ComEd Debt Retirements. In October 2004, ComEd retired $25 million of 7.625% First Mortgage Bonds due April 15, 2013 and $56 million of 9.20% medium term notes.

      PECO Debt Retirements. In October 2004, PECO retired $156 million of Pollution Control Revenue Refunding Bonds due between April 2021 and October 2034.

      Generation Debt Issuances. In October 2004, Generation issued $156 million of variable rate Pollution Control Revenue Refunding Bonds, due between April 2021 and October 2034 through the Delaware County Industrial Development Authority (Pennsylvania) and the Montgomery County Industrial Development Authority (Pennsylvania).

      Cotter Corporation Litigation (Generation). In October 2004, a settlement of the claims of all Cotter plaintiffs associated with allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs was reached and approved by the Federal

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

District Court in Colorado. This settlement amount approximated Generation’s reserve for this matter. Settlements with the two primary Cotter insurers were also concluded, under which they will pay Generation approximately $20 million, which covers the amount previously reserved as well as certain other costs incurred by Generation related to this matter, by November 2004. Neither of these settlements affect the environmental liability associated with the West Lake Landfill as described in Note 15 — Commitments and Contingencies.

      Generation’s Purchase of Sithe International, Inc. On October 13, 2004, Sithe transferred all the shares of Sithe International, Inc. and its subsidiaries to a subsidiary of Generation in exchange for cancellation of a $92 million note and accrued interest which are currently eliminated as part of the consolidation of Sithe. Sithe International, Inc. indirectly owns a 49.5% interest in TEG, consisting of two petcoke-fired plants in Mexico that commenced commercial operations in the second quarter of 2004.

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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 Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments:

	•	Energy Delivery, whose businesses include the regulated sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and PECO Energy Company (PECO) in southeastern Pennsylvania and the purchase and sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.
	•	Generation, consisting of Exelon Generation Company, LLC’s (Generation) owned and contracted for electric generating facilities, energy marketing operations, a 50% interest in EXRES SHC, Inc., the holding company of Sithe Energies, Inc. and its subsidiaries, hereafter referred to as Sithe, and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.
	•	Enterprises, consisting primarily of the remaining infrastructure and electrical contracting services of Exelon Enterprises Company, LLC and other investments weighted towards the communications and energy services industries. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. See Note 3 — Acquisitions and Dispositions for information regarding the disposition of businesses within the Enterprises segment.

      See Note 17 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, including legal, human resources, financial, information technology, supply management and corporate governance services. Additionally, in 2004, due to the centralization of certain functions, certain employees were transferred from ComEd, PECO and Generation to BSC. As a result, ComEd and PECO now receive additional services from BSC, including planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems, and management of other support services. Generation now receives additional services from BSC for inventory and information technology support and management of other support services. These costs are 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.

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 the 2003 Form 10-K for a discussion of the estimates and judgments necessary in the registrants’ accounting for derivative instruments, regulatory assets and liabilities, nuclear decommissioning, depreciable lives of property, plant and equipment, asset impairments, severance accounting, defined benefit pension and other postretirement welfare benefits, taxation, unbilled energy revenues and environmental costs. Set forth below is an update to the 2003 Form 10-K.

	Accounting for Ownership Interests in Variable Interest Entities (Exelon, ComEd, PECO and Generation)

      As of September 30, 2004, Exelon, through Generation, owns an indirect 50% interest in Sithe. In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Exelon and Generation consolidated Sithe within their financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN No. 46-R required an

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      In addition to Sithe, management reviewed other entities with which Exelon and its subsidiaries have business relationships to determine if those entities were variable interest entities that should be consolidated under FIN No. 46-R and concluded that those entities should not be consolidated within the financial statements of Exelon, ComEd, PECO or Generation.

New Accounting Pronouncements

      See Note 2 of the Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements.

EXELON CORPORATION

Executive Overview

      Financial Results. Exelon’s diluted earnings per average common share were $0.85 for the three months ended September 30, 2004 as compared to a net loss of $0.16 for the same period in 2003, primarily as a result of an increase in net income at Generation, reduced severance and severance-related charges associated with The Exelon Way and favorable effects from investments in synthetic fuel-producing facilities, which were partially offset by decreased net income at Energy Delivery and Enterprises. The increase in Generation’s net income reflects a $945 million impairment charge (before income taxes) recorded during the third quarter of 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating) and a $55 million impairment charge recorded in 2003 related to its investment in Sithe. Exelon’s investments in synthetic fuel-producing facilities increased Exelon’s net income for the three months ended September 30, 2004 by $18 million. The decrease in net income at Energy Delivery reflects charges of $106 million (before income taxes) associated with ComEd’s extinguishment of debt and a decrease in revenues primarily due to unfavorable weather conditions in the ComEd and PECO service territories. Enterprises’ 2003 income reflected a gain on the sale of InfraSource, Inc. (InfraSource) of $44 million (before income taxes).

      Exelon’s diluted earnings per average common share were $2.25 for the nine months ended September 30, 2004 as compared to $0.96 for the same period in 2003, primarily as a result of increased income at Generation, a reduction in severance and severance-related charges associated with The Exelon Way, decreased losses at Enterprises and favorable effects from investments in synthetic fuel-producing facilities, partially offset by decreased net income at Energy Delivery. The increase in Generation’s net income reflects 2003 impairment charges of $945 million and $255 million (before income taxes) related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, respectively. Generation’s 2004 income includes an $85 million gain (before income taxes) on the sale of Boston Generating during the second quarter of 2004. Enterprises results reflect net gains recorded in 2004 related to the dispositions of businesses and investments and investment impairment charges recorded in 2003. Exelon’s investments in synthetic fuel-producing facilities increased its 2004 after-tax earnings by $47 million. Energy Delivery’s net income was negatively affected by debt retirement costs of $106 million (before income taxes).

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      In the first quarter of 2004, Exelon recorded an after-tax gain of $32 million in accordance with FIN No. 46-R and the resulting consolidation of Sithe. In the third quarter of 2004, Exelon recorded an after-tax loss of $9 million upon the adoption of EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). In the first quarter of 2003, Exelon recorded an after-tax gain of $112 million upon the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Asset Retirement Obligations” (SFAS No. 143).

      The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Exelon — Executive Summary” in the 2003 Form 10-K for a discussion of Exelon’s implementation of The Exelon Way.

      Investment Strategy. Exelon continued to follow a disciplined approach in investing to maximize the earnings and cash flows from its assets and businesses and to divest those assets and businesses that do not meet its goals. Highlights in the first nine months of 2004 include:

	•	On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns the companies that own the Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility. The resulting pre-tax gain of $85 million ($52 million after-tax) was recorded within Exelon’s Consolidated Statements of Income and Comprehensive Income during the second quarter of 2004. On September 1, 2004, Generation completed the transfer of plant operations and power marketing arrangements to the lenders’ special purpose entity and its contractors under Boston Generating’s credit facility.
	•	On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. Generation’s intent is to fully divest its interest in Sithe, and Generation is actively pursuing opportunities to dispose of Sithe. Generation believes that exercising its call option will provide it with greater certainty of a timely exit from Sithe on favorable terms and conditions.
	•	Exelon continued to execute its divestiture strategy for Enterprises by selling substantially all components of Exelon Services, Inc. (Services) during the nine months ended September 30, 2004 for total expected proceeds of $35 million subject to post-closing adjustments, and by selling its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million in June 2004. Exelon closed on the sale of Exelon Thermal Holding, Inc.’s (Thermal) Chicago business during the second quarter of 2004 for net cash proceeds of $134 million and closed on the sale of ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC (Aladdin), for a net cash outflow of $1 million in September 2004.

      Enterprises continues to pursue the divestiture of other businesses and investments; however, it may be unable to fully divest certain businesses and investments for a number of reasons, including an inability to locate appropriate buyers or negotiate acceptable terms for the transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to market conditions that may contribute to pricing and other terms that are materially less than expected and could result in a loss on the sale. Timing of any divestitures may positively or negatively affect the results of operations. As of September 30, 2004, Enterprises had total assets and liabilities of $278 million and $82 million, respectively.

      Financing Activities. Exelon met its capital resource commitments 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, 2004, ComEd retired $768 million of its outstanding debt pursuant to an accelerated liability management plan. ComEd plans to retire over $400 million of long-term debt in the fourth quarter of 2004 to complete its accelerated liability management plan. In addition to the accelerated liability management plan, payments of approximately $547 million were made for the purpose of retiring PECO and ComEd transition trust long-term debt and approximately $107 million of other net long-term debt during 2004. In January 2004, Exelon approved a 2-for-1 split of its common stock with a distribution date of May 5, 2004. In the second quarter of 2004, Exelon’s Board of Directors approved a discretionary share repurchase program, and Exelon purchased common stock held as

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      Regulatory Developments — PJM Integration. On May 1, 2004, ComEd fully integrated its transmission facilities into PJM Interconnection (PJM). PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $30 million annually. Exelon believes such costs will ultimately be partially offset by the benefits of full access to a wholesale competitive marketplace and increased revenue requirements, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.

      Through and Out Proceeding. ComEd and PECO currently recognize approximately $66 million and $4 million, respectively, of annual revenue from through and out (T&O) rates for energy flowing across ComEd’s and PECO’s transmission systems. On March 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM, the Midwest ISO and other parties filed various pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. On October 1, 2004, ComEd and PECO participated in the filing of a Regional Pricing Proposal which, if accepted by the FERC, could minimize ComEd’s and PECO’s losses of T&O revenues. Depending upon which proposal is accepted by the FERC, or if the FERC creates a new alternative, ComEd’s and PECO’s results of operations could be negatively affected.

      Rate Design Proceeding. Additionally, certain PJM transmission owners, including ComEd and PECO, are subject to a rate design proceeding. One or more filings will be made in January 2005 to address, among other items, how costs associated with new investments should be recovered. Exelon is presently evaluating the extent to which ComEd and PECO will participate in this proceeding.

      At this early stage, Exelon cannot predict the outcome of either of the above proceedings; however, these proceedings could lead to adverse impacts on Exelon’s results of operations.

      See ComEd’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Overview” for further information regarding Regulatory Developments.

      Operations. Generation’s nuclear fleet achieved a 94.1% capacity factor for the nine months ended September 30, 2004 compared to 94.5% in the same period of 2003 primarily as a result of increased planned outage days.

      Outlook for the Remainder of 2004 and Beyond. Through September 30, 2004, Exelon has purchased interests in three synthetic fuel-producing facilities. Exelon’s purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. Synthetic fuel facilities produce fuel used in power plants by chemically changing coal, including waste and marginal coal. The production and sale of synthetic fuel entitles the owner of the synthetic fuel facilities to tax credits under Section 29 of the Internal Revenue Code.

      Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits as the annual average wellhead price per barrel of domestic crude oil increases into an inflation-adjusted phase-out range. For 2003, the tax credit would have begun to phase-out when the annual average wellhead price per barrel of domestic crude oil exceeded $50.14 per barrel and would have

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      Due to the low price of domestic crude oil during the first part of 2004, the phase-out is not expected to affect Exelon’s tax credits or net income from the facilities for 2004. If domestic crude oil prices remain high in 2005, the tax credits and net income generated by the investments may be reduced substantially. In addition, Exelon has recorded an intangible asset related to its investments in these facilities that could become impaired if domestic crude oil prices continue to increase in the future.

Results of Operations — Exelon Corporation

	Three Months Ended September 30, 2004 Compared To Three Months Ended September 30, 2003

		Three Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	3,865			$	4,441			$	(576	)
Purchased power and fuel expense			1,280				1,863				583
Impairment of Boston Generating, LLC long-lived assets			—				945				945
Operating and maintenance expense			815				1,203				388
Depreciation and amortization			364				293				(71	)
Operating income			1,228				6				1,222
Other income and deductions			(370	)			(220	)			(150	)
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principle			858				(214	)			1,072
Income (loss) before cumulative effect of change in accounting principle			577				(102	)			679
Net income (loss)			568				(102	)			670
Diluted earnings (loss) per share			0.85				(0.16	)			1.01

      Operating Revenues. Operating revenues decreased for the three months ended September 30, 2004 as compared to the same period in 2003 primarily due to decreased revenues at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003, Generation’s adoption of Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’ ” (EITF 03-11) in 2004, Generation’s sale of Boston Generating during the second quarter of 2004 and unfavorable weather conditions at Energy Delivery. Generation’s adoption of EITF 03-11 during 2004 changed the presentation of certain power transactions and decreased operating revenues by $272 million for the three months ended September 30, 2004 but had no effect on net income, as the decrease in revenue was offset by a comparable decrease in purchased power and fuel costs. The decreases in operating revenues were partially offset by an increase in market sales at Generation due to the acquisition of the remaining 50% of AmerGen Energy Company, LLC (AmerGen) and the consolidation of Sithe and higher weather-normalized delivery volume at Energy Delivery. See further discussion of operating revenues by segment below.

      Purchased Power and Fuel Expense. Purchased power and fuel expense decreased during the three months ended September 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004, which resulted in a decrease in purchased power and fuel expense of $272 million, the sale of Boston Generating during the second quarter of 2004 and favorable mark-to-market adjustments. In addition, purchased power decreased due to reduced capacity payments to Midwest

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      Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during the third quarter of 2003 to impair the long-lived assets of Boston Generating.

      Operating and Maintenance Expense. Operating and maintenance expense decreased for the three months ended September 30, 2004 as compared to the same period in 2003 primarily due to a decrease in severance and severance-related charges associated with The Exelon Way, adjustments related to Generation’s nuclear decommissioning accounting recorded during the third quarter of 2004, decreased expenses at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003 and a gain recorded in 2004 resulting from a settlement with the Department of Energy (DOE) related to spent nuclear fuel, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen and the consolidation of Sithe and investments made by Exelon in the fourth quarter of 2003 in synthetic fuel-producing facilities. See further discussion of operating and maintenance expenses by segment below.

      Depreciation and Amortization Expense. The increase in depreciation and amortization expense is primarily due to additional plant placed in service after the third quarter of 2003 at Energy Delivery and Generation, the recording and subsequent impairment of an asset retirement cost asset (ARC) at Generation in 2004 and increased amortization expense due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. The increase is also due to increased competitive transition charge amortization at PECO.

      Operating Income. Exclusive of the changes in operating revenues, purchased power and fuel expense, operating and maintenance expense and depreciation and amortization expense discussed above, the change in operating income was primarily the result of increased taxes other than income in 2004 as compared to 2003, primarily due to the reversal of real estate tax accruals at PECO and Generation during the third quarter of 2003.

      Other Income and Deductions. Other income and deductions reflects debt retirement charges of $106 million recorded at ComEd in 2004 associated with an accelerated liability management plan and a $55 million impairment loss recorded in 2003 related to Generation’s investment in Sithe. Equity in earnings of unconsolidated affiliates decreased due to the acquisition of the remaining 50% of AmerGen in December 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities.

      Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 52% for the three months ended September 30, 2003 to 33% for the same period in 2004, primarily due to the impact on income before income taxes of the impairment of Boston Generating’s long-lived assets recorded in 2003 and investments made in synthetic fuel-producing facilities during the fourth quarter of 2003. Also, the decrease in the rate is attributable to the state tax benefits at Exelon Generation, which incurred losses for the three months ended September 30, 2003, compared to the state tax expense for the remainder of Exelon and its subsidiaries. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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	Results of Operations by Business Segment

      Exelon evaluates its performance on a business segment basis. The comparisons of operating results and other statistical information for the three months ended September 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

      Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The information for the three months ended September 30, 2003 related to the Generation and Enterprises segments discussed below has been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s results for the three months ended September 30, 2003 were as follows:

Total revenues		$	146
Intersegment revenues			—
Loss before income taxes			(5	)
Income tax benefit			(2	)
Net loss			(3	)

	Net Income (Loss) by Business Segment

		Three Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Energy Delivery		$	262			$	303			$	(41	)
Generation			319				(431	)			750
Enterprises			(20	)			19				(39	)
Corporate			7				7				—
Total		$	568			$	(102	)		$	670

	Results of Operations — Energy Delivery

		Three Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	2,844			$	2,886			$	(42	)
Purchased power and fuel expense			1,400				1,401				1
Operating and maintenance expense			353				491				138
Depreciation and amortization expense			248				231				(17	)
Operating income			711				664				47
Interest expense			162				182				20
Other, net			(98	)			5				(103	)
Income before income taxes			440				479				(39	)
Income taxes			178				176				(2	)
Net income			262				303				(41	)

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      Operating Revenues. The changes in Energy Delivery’s operating revenues for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

										Total
										Increase
		Electric				Gas				(Decrease)
Weather		$	(188	)		$	—			$	(188	)
Customer choice			(27	)			—				(27	)
Volume			114				—				114
PJM transmission			59				—				59
Rate changes and mix			11				7				18
Other effects			(18	)			—				(18	)
(Decrease) increase in operating revenues		$	(49	)		$	7			$	(42	)

      Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. Energy Delivery’s electric revenues were negatively affected by unfavorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 27% and 16% lower, respectively, than the prior year period.

      Customer Choice. For the three months ended September 30, 2004 and 2003, 28% and 24%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by alternative energy suppliers (AES) or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $6 million from customers in Illinois electing to purchase energy from an AES or under the ComEd PPO and a decrease in revenues of $21 million from customers in Pennsylvania being assigned to or selecting an AES.

      Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large and small commercial and industrial customers for ComEd and across all customer classes for PECO.

      PJM Transmission. Energy Delivery’s operating revenues and purchased power expense each increased by $63 million in the three months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM partially offset by $4 million of lower transmission revenues and expenses at PECO. The increases related to the change in control of the transmission assets from ComEd to PJM as a result of which ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. This is consistent with how PECO accounts for its PJM transmission revenues and expenses. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million. However, there is no expected effect on revenues net of purchased power expense.

      Rate Changes and Mix. ComEd’s competitive transition charge (CTC) is reset in the second quarter of each year to reflect market price adjustments. As a result, ComEd’s CTC revenues decreased $11 million for the three months ended September 30, 2004 as compared to the same period in 2003. This decrease was offset by increased wholesale market prices that increased energy revenue received under ComEd’s power purchase option (PPO) and by increased average rates paid by small and large commercial and industrial customers totaling $11 million.

      Increased average rates paid by ComEd’s residential customers resulted in a $10 million increase in revenues. Although residential rates are frozen through 2006, ComEd’s average effective residential rates fluctuate due to the usage patterns of customers.

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      Electric revenues were unchanged at PECO as a result of a $7 million unfavorable rate mix due to changes in monthly usage patterns in all customer classes, offset by a $7 million increase related to a scheduled phase-out of merger-related rate reductions. In connection with the Pennsylvania Public Utility Commission’s (PUC) approval of the merger of PECO and Unicom Corporation into Exelon in 2000, PECO entered into a settlement agreement with intervening parties and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005. Consequently, rates were reduced from the levels that otherwise would have been in effect pursuant to the PUC approved restructuring settlement by $60 million annually until January 1, 2004 when the reduction decreased to $40 million annually, which will be in effect through December 31, 2005.

      Energy Delivery’s gas revenues reflect increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective March 1, 2004. The average purchased gas cost rate per million cubic feet for the three months ended September 30, 2004 was 22% higher than the rate for the same period in 2003. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO anticipates that its purchased gas cost rates will be reduced effective December 1, 2004 in connection with a settlement approved by the PUC in September 2004. This decrease will have no impact on PECO’s operating income.

      Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

										Total
										Increase
		Electric				Gas				(Decrease)
Weather		$	(87	)		$	—			$	(87	)
Customer choice			(23	)			—				(23	)
Prices			(4	)			7				3
Volume			56				—				56
PJM transmission			59				—				59
Other			(9	)			—				(9	)
(Decrease) increase in purchased power and fuel expense		$	(8	)		$	7			$	(1	)

      Weather. Energy Delivery’s purchased power and fuel expense decreased due to the effect of unfavorable weather conditions.

      Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an AES or under the ComEd PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from an AES.

      Prices. Energy Delivery’s electric purchased power decreased primarily due to the mix of average pricing related to ComEd’s PPA with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

      Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large and small commercial and industrial customers. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer across all customer classes.

      PJM Transmission. Energy Delivery’s operating revenues and purchased power expense each increased by $63 million in the three months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004

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      Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Severance, pension and postretirement benefit costs associated with The Exelon Way		$	(93	)
Incremental storm costs			(23	)
Automated meter reading system implementation costs at PECO in 2003			(13	)
Decrease in payroll expense due to fewer employees(a)			(12	)
FERC annual fees(b)			(11	)
Allowance for uncollectible accounts expense			(9	)
Higher corporate allocations(c)			20
Contractors			7
Other			(4	)
Decrease in operating and maintenance expense		$	(138	)

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(a)		Energy Delivery has fewer employees as a result of The Exelon Way terminations.
(b)		After joining PJM on May 1, 2004, ComEd is no longer charged annual fees by the FERC. PJM pays the annual FERC fees. This represents the reversal of annual FERC fees.
(c)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in Energy Delivery comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

     Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased CTC amortization of $12 million at PECO and increased depreciation of $5 million due to capital additions across Energy Delivery.

      Operating Income. Operating income, exclusive of the changes discussed above, decreased as a result of increased taxes other than income. The increase in taxes other than income was primarily attributable to $58 million at PECO related to the reversal of real estate tax accruals during 2003, partially offset by $8 million in additional use tax payments in 2003 at ComEd and an $8 million refund at ComEd in 2004 for Illinois Electricity Distribution Taxes.

      Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates.

      Other, net. In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt. Exelon and ComEd recorded a charge of $106 million associated with the retirement of debt under the plan. The components of this charge included the following: $63 million related to prepayment premiums; $11 million related to net unamortized premiums, discounts and debt issuance costs; $23 million of losses on reacquired debt previously deferred as regulatory assets; and $9 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets. In 2003, PECO reversed an accrual for interest income on Federal income taxes of $14 million to reflect actual interest received.

      Income taxes. At ComEd, the effective income tax rate was 43% for the three months ended September 30, 2004, compared to 39% for the three months ended September 30, 2003. At PECO, the effective tax rate was 37% for the three months ended September 30, 2004 as compared to 35% for the same period in 2003. The increases in the effective tax rates were primarily attributable to adjustments to prior period income taxes in connection with the completion of the 2003 tax returns. See Note 12 of the Combined

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	Energy Delivery Operating Statistics and Revenue Detail

      Energy Delivery’s electric sales statistics and revenue detail were as follows:

			Three Months
			Ended
			September 30,
Retail Deliveries — (in gigawatthours (GWhs))(a)			2004				2003				Variance				% Change
Full service(b)
Residential				10,340				11,530				(1,190	)			(10.3	)%
Small commercial & industrial				7,099				7,502				(403	)			(5.4	)%
Large commercial & industrial				5,447				5,552				(105	)			(1.9	)%
Public authorities & electric railroads				1,447				1,486				(39	)			(2.6	)%
	Total full service			24,333				26,070				(1,737	)			(6.7	)%
PPO (ComEd only)
Small commercial & industrial				1,053				884				169				19.1	%
Large commercial & industrial				1,160				896				264				29.5	%
Public authorities & electric railroads				562				428				134				31.3	%
				2,775				2,208				567				25.7	%
Delivery only(c)
Residential				636				258				378				146.5	%
Small commercial & industrial				2,318				2,241				77				3.4	%
Large commercial & industrial				3,315				3,142				173				5.5	%
Public authorities & electric railroads				371				426				(55	)			(12.9	)%
				6,640				6,067				573				9.4	%
	Total PPO and delivery only			9,415				8,275				1,140				13.8	%
Total retail deliveries				33,748				34,345				(597	)			(1.7	)%

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(a)		One GWh is the equivalent of one million kilowatthours (kWh).
(b)		Full service reflects deliveries to customers taking electric generation service under tariffed rates.
(c)		Delivery only service reflects customers receiving electric generation service from an AES.

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			Three Months
			Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	1,108			$	1,226			$	(118	)			(9.6	)%
Small commercial & industrial				676				698				(22	)			(3.2	)%
Large commercial & industrial				366				374				(8	)			(2.1	)%
Public authorities & electric railroads				97				101				(4	)			(4.0	)%
	Total full service			2,247				2,399				(152	)			(6.3	)%
PPO (ComEd only)(b)
Small commercial & industrial				76				65				11				16.9	%
Large commercial & industrial				71				56				15				26.8	%
Public authorities & electric railroads				33				26				7				26.9	%
				180				147				33				22.4	%
Delivery only(c)
Residential				50				20				30				150.0	%
Small commercial & industrial				59				62				(3	)			(4.8	)%
Large commercial & industrial				47				46				1				2.2	%
Public authorities & electric railroads				8				8				—				—
				164				136				28				20.6	%
	Total PPO and delivery only			344				283				61				21.6	%
Total electric retail revenues				2,591				2,682				(91	)			(3.4	)%
	Wholesale and miscellaneous revenue(d)			193				151				42				27.8	%
Total electric revenue			$	2,784			$	2,833			$	(49	)			(1.7	)%

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(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC.
(b)		Revenue from customers choosing the ComEd PPO includes an energy charge at market rates, transmission and distribution charges and a CTC.
(c)		Delivery only revenue reflects revenue from customers receiving electric generation service from an AES. Revenue from customers choosing an AES includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from an AES were included in wholesale and miscellaneous revenue.
(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

     Energy Delivery’s gas sales statistics and revenue detail were as follows:

		Three Months
		Ended
		September 30,
Deliveries to customers (in million cubic feet (mmcf))		2004				2003				Variance				% Change
Retail sales			3,866				3,498				368				10.5	%
Transportation			6,167				6,012				155				2.6	%
Total			10,033				9,510				523				5.5	%

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		Three Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Retail sales		$	55			$	47			$	8				17.0	%
Transportation			4				4				—				—
Resales and other			1				2				(1	)			(50.0	)%
Total		$	60			$	53			$	7				13.2	%

     Results of Operations — Generation

      As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion within this segment analysis, Exelon Energy Company’s results of operations have been included within Generation’s results of operations as if this transfer had occurred on January 1, 2003.

		Three Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	2,253			$	2,630			$	(377	)
Purchased power and fuel expense			1,122				1,780				658
Impairment of Boston Generating, LLC long-lived assets			—				945				945
Operating and maintenance expense			432				513				81
Depreciation and amortization expense			95				52				(43	)
Operating income			562				(688	)			1,250
Income before income taxes and minority interest			517				(713	)			1,230
Net income			319				(431	)			750

      Operating Revenues. For the three months ended September 30, 2004 and 2003, Generation’s sales were as follows:

		Three Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates		$	1,218			$	1,286			$	(68	)			(5.3	)%
Wholesale and retail electric sales			759				1,148				(389	)			(33.9	)%
Total energy sales revenue			1,977				2,434				(457	)			(18.8	)%
Retail gas sales			55				78				(23	)			(29.5	)%
Trading portfolio			1				1				—				—
Other revenue(a)			220				117				103				88.0	%
Total revenue		$	2,253			$	2,630			$	(377	)			14.3	%

---

(a)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

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		Three Months
		Ended
		September 30,
Sales (in GWhs)		2004(a)				2003				Variance				% Change
Electric sales to affiliates			30,040				31,113				(1,073	)			(3.4	)%
Wholesale and retail electric sales			21,894				31,177				(9,283	)			(29.8	)%
Total sales			51,934				62,290				(10,356	)			(16.6	)%

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(a)		Sales in 2004 do not include 6,919 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.

     Trading volumes of 7,132 GWhs and 11,086 GWhs for the three months ended September 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

      Generation’s average margin (operating revenue, less purchased power and fuel expenses) and other operating data for the three months ended September 30, 2004 and 2003 were as follows:

			Three Months
			Ended
			September 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates		$	40.55			$	41.33				(1.9	)%
	Wholesale and retail electric sales			34.67				36.82				(5.8	)%
	Total — excluding the trading portfolio			38.07				39.08				(2.6	)%
Average supply cost(a) — excluding the trading portfolio			$	21.60			$	28.58				(24.4	)%
Average margin — excluding the trading portfolio			$	16.47			$	10.50				56.9	%

---

(a)		Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003.

     Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11		$	(272	)
Sale of Boston Generating			(213	)
AmerGen operations			77
Other			19
Decrease in wholesale and retail electric sales		$	(389	)

      The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. See Note 2 of the Combined Notes to Consolidated Financial Statements for further discussion of EITF 03-11. The sale of Boston Generating in May 2004 decreased wholesale and retail sales, which was partially offset by the increase from the acquisition of the remaining 50% of AmerGen in 2003.

      The increase in other wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market as a result of forward hedging and fuel prices, and higher average market prices driven by coal prices in the Midwest, and higher oil and gas prices in the Mid-Atlantic region contributed to higher revenues.

      Electric Sales to Affiliates. The decrease in revenue from sales to affiliates was due to lower sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to customers purchasing energy from

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      Retail Gas Sales. Retail gas sales decreased $23 million as a result of the wind down of Exelon Energy’s Northeast business.

      Other. Certain other revenues increased for the three months ended September 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s operations beginning April 1, 2004.

      Purchased Power and Fuel Expense. Generation’s supply source is summarized below:

		Three Months
		Ended
		September 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			35,303				30,152				5,151				17.1	%
Purchases — non-trading portfolio(b)			13,563				24,502				(10,939	)			(44.6	)%
Fossil and hydroelectric generation(c)			3,068				7,636				(4,568	)			(59.8	)%
Total supply			51,934				62,290				(10,356	)			(16.6	)%

---

(a)		Excludes AmerGen in 2003. AmerGen generated 5,151 GWhs during the three months ended September 30, 2004.
(b)		6,919 GWhs were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 3,725 GWhs in 2003.
(c)		Fossil generation associated with the Boston Generating units represented 3,570 GWhs during the three months ended September 30, 2003.

     The changes in Generation’s purchased power and fuel expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11		$	(272	)
Boston Generating			(178	)
AmerGen operations			(124	)
Mark-to-market adjustments on hedging activity			(78	)
Midwest Generation			(62	)
Sithe			52
Volume			17
Price			42
Other			(55	)
Decrease in purchased power and fuel expense		$	(658	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in reported purchased power and fuel expense of $272 million.

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due to the sale of the business in May 2004.

      AmerGen. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $124 million, which had a significant impact on Generation’s average supply cost decrease for the same period. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense.

      Hedging Activity. Mark-to-market gains on hedging activities were $57 million for the three months ended September 30, 2004 compared to losses of $21 million for the same period of 2003.

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      Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation.

      Sithe. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.

      Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power was partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

      Price. The increase reflects higher market energy prices due to higher natural gas, oil and coal prices.

      Other. Other decreases in purchased power and fuel expense were primarily due to $20 million of lower fuel expense due to the wind down of Exelon Energy’s northeast business and $20 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM during the second quarter of 2004.

      Impairment of the Long-Lived Assets of Boston Generating. In connection with the decision to transition out of the ownership of Boston Generating and the projects during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

      Operating and Maintenance Expense. The changes in operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Pension, payroll and benefit costs, primarily associated with The Exelon Way		$	(51	)
DOE settlement(a)			(52	)
Boston Generating			(21	)
AmerGen			77
Sithe			18
Other			(52	)
Decrease in operating and maintenance expense		$	(81	)

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(a)		See Note 15 of the Combined Notes to consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement reached with the DOE.

     The decrease in operating and maintenance expense was primarily due to reductions in payroll-related costs associated with the implementation of the programs associated with The Exelon Way, a reduction in operating and maintenance expense resulting from the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel, the sale of Boston Generating in May 2004, and a $36 million reduction in the contractual obligation that Generation has to ComEd related to decommissioning obligations. Generation is required to refund ComEd the amount of decommissioning trust fund assets in excess of the asset retirement obligation (ARO), if any, at the completion of the decommissioning of the former ComEd nuclear units. In the third quarter of 2004, Generation updated the ARO for the former ComEd plants and was required to impair an asset established during this process (see Depreciation and Amortization discussion below). The obligation to ComEd was reduced due to this impairment charge and as such, operating expense was reduced by an equal amount. These decreases in operating and maintenance expense were partially offset by the inclusion of AmerGen and Sithe’s operating results in Generation’s consolidated results for 2004.

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      Nuclear fleet operating data and purchased power cost data for the three months ended September 30, 2004 and 2003 were as follows:

		Three Months
		Ended
		September 30,
		2004				2003
Nuclear fleet capacity factor(a)			95.8	%			95.3	%
Nuclear fleet production cost per MWh(a)		$	10.92			$	11.69
Average purchased power cost for wholesale operations per MWh(b)		$	54.78			$	51.53

---

(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).
(b)		Includes PPAs with AmerGen in 2003.

     Higher nuclear capacity factors were primarily due to four fewer planned refueling outage days. The four fewer outage days resulted in a $12 million decrease in planned outage costs for the three months ended September 30, 2004 as compared to the same period in 2003. There was one planned outage during the three months ended September 30, 2004, compared to two planned outages during the same period in 2003. The three months ended September 30, 2004 included four unplanned outages compared to nine unplanned outages during the same period in 2003.

      Lower nuclear production costs were primarily due to higher nuclear fuel capacity and the spent fuel storage cost settlement agreement with the DOE which resulted in the reimbursement of $40 million in spent fuel storage costs incurred as operating and maintenance expenses prior to September 30, 2003, and the recording of $12 million of spent fuel storage operating and maintenance expenses incurred from October 1, 2003 to September 30, 2004 as an Other Account Receivable.

      In the three months ended September 30, 2004 as compared to the three months ended September 30, 2003, the Quad Cities units operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.

      Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended September 30, 2004 as compared to the same period in 2003 was primarily due to the establishment of an ARC asset for retired nuclear units of $36 million associated with the third quarter 2004 update of the nuclear decommissioning ARO. This ARC was immediately impaired through depreciation expense as this asset was associated with retired nuclear units that do not have any remaining useful life. The remaining increase is due to capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

      Effective Income Tax Rate. The effective income tax rate was 38% for the three months ended September 30, 2004 compared to 40% for the same period in 2003. This decrease is primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe which resulted in a pre-tax loss. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

	Results of Operations — Enterprises

      As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises

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		Three Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	15			$	291			$	(276	)
Operating and maintenance expense			19				257				238
Operating income (loss)			(4	)			29				(33	)
Other income and deductions			(13	)			2				(15	)
Income (loss) before income taxes and cumulative effect of a change in accounting principle			(17	)			31				(48	)
Income (loss) before cumulative effect of a change in accounting principle			(11	)			19				(30	)
Cumulative effect of a change in accounting principle			(9	)			—				(9	)
Net income (loss)			(20	)			19				(39	)

      Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ results for the three and nine months ended September 30, 2004 compared to the three months and nine ended September 30, 2003 were significantly affected by the following transactions:

      InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource.

      Exelon Services, Inc. During 2004, Enterprises disposed of substantially all of the operating businesses of Services, including Exelon Solutions, most mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the three months ended September 30, 2004 related to the disposition of these Services businesses were $6 million and $1 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of September 30, 2004, Services had assets and liabilities of $66 million and $14 million, respectively, which primarily represented the corporate operations.

      Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Thermal for proceeds of $134 million, subject to working capital adjustments. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, which resulted in prepayment penalties of $9 million, which were recorded as interest expense. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income.

      On September 29, 2004, Enterprises closed on the sale of ETT Nevada, Inc., the holding company for its investment in Aladdin, for a net cash outflow of $1 million, subject to working capital adjustments. A pre-tax loss of $3 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income inclusive of the acquisition and sale of Aladdin’s third-party debt associated with the transaction.

      PECO Telcove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.

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      Operating Revenues. The changes in Enterprises’ operating revenues for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
InfraSource businesses		$	(132	)
Services(a)			(97	)
F&M Holdings, LLC(b)			(27	)
Other			(20	)
Decrease in operating revenues		$	(276	)

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(a)		Primarily due to the sale of certain businesses.
(b)		For the remaining businesses of F & M Holdings, LLC, operating revenues decreased as a result of the sale of certain businesses and wind-down efforts.

     Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
InfraSource businesses		$	(79	)
Services(a)			(90	)
F & M Holdings, LLC(b)			(35	)
Thermal(a)			(9	)
Other			(25	)
Decrease in operating and maintenance expense		$	(238	)

---

(a)		Primarily due to the sale of businesses.
(b)		For the remaining businesses of F & M Holdings, LLC, operating and maintenance expense decreased as a result of the sale of certain businesses and wind-down efforts.

     Other Income and Deductions. The decrease in other income and deductions was primarily due to impairments of investments recorded in 2004.

      Effective Income Tax Rate. The effective income tax rate was 35% for the three months ended September 30, 2004 compared to 39% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to state tax impact on the sale of investments at ECPH, LLC.

      Cumulative Effect of a Change in Accounting Principle. Enterprises adopted EITF 03-16 on July 1, 2004, which required Enterprises to account for certain of its limited liability partnerships under the equity method of accounting. Enterprises recorded an after-tax impairment charge of $9 million as a cumulative effect of a change in accounting principle upon adoption of EITF 03-16.

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	Results of Operations — Exelon Corporation

	Nine Months Ended September 30, 2004 Compared To Nine Months Ended September 30, 2003

		Nine Months Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	11,137			$	12,236			$	(1,099	)
Purchased power and fuel expense			3,888				4,983				1,095
Impairment of Boston Generating, LLC long-lived assets			—				945				945
Operating and maintenance expense			2,921				3,362				441
Depreciation and amortization expense			980				842				(138	)
Operating income			2,792				1,615				1,177
Other income and deductions			(668	)			(835	)			167
Income before income taxes, minority interest and cumulative effect of changes in accounting principles			2,124				780				1,344
Income before cumulative effect of changes in accounting principles			1,478				519				959
Cumulative effect of changes in accounting principles			23				112				(89	)
Net income			1,501				631				870
Diluted earnings per share			2.25				0.96				1.29

      Operating Revenues. Operating revenues decreased for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 in the first quarter of 2004, which changed the presentation of certain power transactions and decreased operating revenues by $724 million, and decreased revenues at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003. The adoption of EITF 03-11 had no impact on net income. Operating revenues were favorably affected by Generation’s acquisition of the remaining 50% of AmerGen and the consolidation of Sithe. See further discussion of operating revenues by segment below.

      Purchased Power and Fuel Expense. Purchased power and fuel expense decreased during the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $724 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in December 2003, which was only partially offset by an increase in fuel expense, and the sale of Boston Generating in the second quarter of 2004. Purchased power represented 24% of Generation’s total supply for the nine months ended September 30, 2004 compared to 37% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.

      Impairment of Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during the third quarter of 2003 to impair the long-lived assets of Boston Generating.

      Operating and Maintenance Expense. Operating and maintenance expense decreased for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to decreased expenses at Enterprises due to the sale of the majority of its businesses since the third quarter of 2003, a decrease in severance and severance-related charges associated with the Exelon Way and decreased expenses at Energy Delivery due to a $41 million charge recorded in 2003 related to an agreement with various Illinois retail market participants and other interested parties, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen. Operating and maintenance expense increased $69 million due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. See further discussion of operating and maintenance expenses by segment below.

      Depreciation and Amortization Expense. The increase in depreciation and amortization expense is primarily due to additional plant placed in service after the third quarter of 2003 at Energy Delivery and Generation, the recording and subsequent impairment of an ARC asset at Generation in 2004 and increased

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      Operating Income. Exclusive of the changes in operating revenues, purchased power and fuel expense, operating and maintenance expense and depreciation and amortization expense discussed above, the change in operating income was primarily the result of increased taxes other than income in 2004 as compared to 2003, primarily due to the reversal of real estate tax accruals at PECO and Generation during the third quarter of 2003.

      Other Income and Deductions. Other income and deductions reflects debt retirement charges of $106 million recorded at ComEd in 2004 associated with an accelerated liability management plan, impairment charges of $255 million (before income taxes) recorded during 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the 2004 sale of Boston Generating and a $36 million gain on the sale of Thermal in 2004 (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $179 million due to the acquisition of the remaining 50% of AmerGen in December 2003, the deconsolidation of certain financing trusts during 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities.

      Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 33% for the nine months ended September 30, 2003 to 31% for the same period in 2004, primarily due to investments made in synthetic fuel-producing facilities during the fourth quarter of 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

      Cumulative Effect of Changes in Accounting Principles. Net income for the nine months ended September 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R and a charge of $9 million, net of income taxes, due to the adoption of EITF 03-16 and the resulting impairment of certain limited liability partnerships at Enterprises. Net income for the nine months ended September 30, 2003 reflects income of $112 million, net of income taxes, for the adoption of SFAS No. 143. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN No. 46-R and SFAS No. 143.

	Results of Operations by Business Segment

      The comparisons of operating results and other statistical information for the nine months ended September 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

      Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for the nine months ended September 30, 2003 related to the Generation and Enterprises segments discussed below has been adjusted to reflect the transfer of Exelon Energy Company from the Enterprises segment to the Generation segment. Exelon Energy Company’s results for the nine months ended September 30, 2003 were as follows:

Total revenues		$	651
Intersegment revenues			4
Loss before income taxes			(20	)
Income tax benefit			(8	)
Net loss			(12	)

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	Income (Loss) Before Cumulative Effect of Change in Accounting Principle by Business Segment

		Nine Months Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Energy Delivery		$	880			$	920			$	(40	)
Generation			567				(351	)			918
Enterprises			—				(50	)			50
Corporate			31				—				31
Total		$	1,478			$	519			$	959

	Net Income (Loss) by Business Segment

		Nine Months Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Energy Delivery		$	880			$	925			$	(45	)
Generation			599				(243	)			842
Enterprises			(9	)			(51	)			42
Corporate			31				—				31
Total		$	1,501			$	631			$	870

	Results of Operations — Energy Delivery

		Nine Months Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	7,853			$	7,850			$	3
Purchased power and fuel expense			3,639				3,576				(63	)
Operating and maintenance expense			1,056				1,234				178
Depreciation and amortization expense			704				657				(47	)
Operating income			2,054				2,025				29
Interest expense			517				565				48
Other, net			(76	)			48				(124	)
Income before income taxes and cumulative effect of a change in accounting principle			1,426				1,478				(52	)
Income before cumulative effect of a change in accounting principle			880				920				(40	)
Net income			880				925				(45	)

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      Operating Revenues. The changes in Energy Delivery’s operating revenues for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

										Total
										Increase
		Electric				Gas				(Decrease)
Volume		$	272			$	(1	)		$	271
PJM transmission			93				—				93
Rate changes and mix			(60	)			89				29
Customer choice			(176	)			—				(176	)
Weather			(174	)			(21	)			(195	)
Other effects			(27	)			8				(19	)
(Decrease) increase in operating revenues		$	(72	)		$	75			$	3

      Volume. Both ComEd’s and PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large and small commercial and industrial customers for ComEd and across all customer classes for PECO.

      PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $106 million in the nine months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM partially offset by $13 million of lower transmission revenues and expenses at PECO.

      Rate Changes and Mix. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component decreased the collection of CTCs as compared to the respective prior year period. As a result, ComEd’s CTC revenues decreased by $131 million for the nine months ended September 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $58 million. For the nine months ended September 30, 2004 and September 30, 2003, ComEd collected approximately $131 million and $262 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, and increases in ComEd’s open access transmission tariff rates (OATT) effective May 1, 2004, ComEd anticipates that this revenue source will decline to approximately $180 million for 2004 and range from $100 million to $180 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

      Electric revenues increased $2 million at PECO as a result of a $16 million increase related to a scheduled phase out of merger-related rate reductions, offset by a $14 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003.

      Energy Delivery’s gas revenues increased due to increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the nine months ended September 30, 2004 was 38% higher than the rate for the same period in 2003.

      Customer Choice. For the nine months ended September 30, 2004 and 2003, 28% and 24%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by an AES or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $113 million from customers in Illinois electing to purchase energy from an AES or under the ComEd PPO and a decrease in revenues of $63 million from customers in Pennsylvania being assigned to or selecting an AES.

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      Weather. Energy Delivery’s electric revenues were negatively affected by unfavorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 12% lower and relatively unchanged, respectively, for the nine months ended September 30, 2004 as compared to the same period in 2003. Heating degree-days were 8% lower in both the ComEd and PECO service territories for the nine months ended September 30, 2004 as compared to the same period in 2003.

      Energy Delivery’s gas revenues were affected by unfavorable weather conditions.

      Purchased Power and Fuel Expense. The changes in Energy Delivery’s purchased power and fuel expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

										Total
										Increase
		Electric				Gas				(Decrease)
Volume		$	137			$	(5	)		$	132
PJM transmission			93				—				93
Prices			(4	)			89				85
Customer choice			(157	)			—				(157	)
Weather			(82	)			(14	)			(96	)
Other			(7	)			13				6
(Decrease) increase in purchased power and fuel expense		$	(20	)		$	83			$	63

      Volume. ComEd’s purchased power and fuel expense increased due to increases, exclusive of the effect of weather and customer choice, in the number of customers and average usage per customer, primarily residential and large and small commercial and industrial customers at ComEd. PECO’s electric purchased power and fuel expense increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer across all customer classes.

      PJM Transmission. Energy Delivery’s transmission revenues and purchased power expense each increased by $106 million in the nine months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM partially offset by $13 million of lower transmission revenues and expenses at PECO. See “Operating Revenues” above.

      Prices. Energy Delivery’s purchased power expense remained relatively unchanged. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

      Customer Choice. An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an AES or under the ComEd PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from an AES.

      Weather. Energy Delivery’s purchased power and fuel expense decreased due to unfavorable weather conditions.

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      Operating and Maintenance Expense. The changes in operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Severance, pension and postretirement benefit costs associated with The Exelon Way		$	(74	)
Charge recorded at ComEd in 2003(a)			(41	)
Decreased payroll expense due to fewer employees(b)			(33	)
Incremental storm costs			(25	)
Automated meter reading system implementation costs at PECO in 2003			(16	)
Allowance for uncollectible accounts expense			(15	)
FERC annual fees(c)			(10	)
Environmental charges			(6	)
Contractors			(3	)
Employee fringe benefits (b, d)			(1	)
Higher corporate allocations(e)			62
Tax Consultant fees(f)			5
Other			(21	)
Decrease in operating and maintenance expense		$	(178	)

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(a)		In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.
(b)		Energy Delivery has fewer employees as a result of The Exelon Way terminations.
(c)		After joining PJM on May 1, 2004, ComEd is no longer charged annual fees by the FERC. PJM pays the annual FERC fees. This represents the reversal of annual FERC fees.
(d)		During the second quarter of 2004, ComEd and PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $8 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
(e)		Higher corporate allocations primarily result from higher corporate allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in Energy Delivery comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.
(f)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 to the Combined Notes to Consolidated Financial Statements for more information).

     Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $26 million at PECO and increased depreciation of $13 million due to capital additions across Energy Delivery.

      Operating Income. Operating income, exclusive of the changes discussed above, decreased as a result of increased taxes other than income of $42 million, which reflects a $58 million increase at PECO offset by a $16 million decrease at ComEd. The increase at PECO was primarily attributable to $58 million related to the reversal of real estate tax accruals during 2003 and $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $5 million of lower capital stock tax. The decrease at ComEd was primarily attributable to $6 million in 2003 for additional use tax payments, a $4 million decrease in payroll taxes as a result of a fewer number of employees, and refunds of $8 million for Illinois Electricity Distribution taxes in 2004 partially offset by refunds of $5 million for Illinois Electricity Distribution taxes in 2003.

      Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates.

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      Other, net. In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt. Exelon recorded a charge of $106 million associated with the retirement of debt under the plan. The components of this charge included the following: $63 million related to prepayment premiums; $11 million related to net unamortized premiums, discounts and debt issuance costs; $23 million of losses on reacquired debt previously deferred as regulatory assets; and $9 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets. In 2003, ComEd recorded income of $12 million resulting from the reduction of a reserve accrual for a potential plant disallowance related to ComEd’s delivery services rate case. In 2003, PECO reversed an accrual for interest on Federal income taxes of $14 million to reflect actual interest received.

	Energy Delivery Operating Statistics and Revenue Detail

      Energy Delivery’s electric sales statistics and revenue detail were as follows:

			Nine Months Ended
			September 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				28,162				28,969				(807	)			(2.8	)%
Small commercial & industrial				20,393				21,555				(1,162	)			(5.4	)%
Large commercial & industrial				15,539				15,896				(357	)			(2.2	)%
Public authorities & electric railroads				4,339				4,710				(371	)			(7.9	)%
	Total full service			68,433				71,130				(2,697	)			(3.8	)%
PPO (ComEd only)
Small commercial & industrial				2,653				2,546				107				4.2	%
Large commercial & industrial				2,784				3,646				(862	)			(23.6	)%
Public authorities & electric railroads				1,574				1,497				77				5.1	%
				7,011				7,689				(678	)			(8.8	)%
Delivery only(b)
Residential				1,706				708				998				141.0	%
Small commercial & industrial				6,707				5,371				1,336				24.9	%
Large commercial & industrial				9,686				7,504				2,182				29.1	%
Public authorities & electric railroads				1,264				954				310				32.5	%
				19,363				14,537				4,826				33.2	%
	Total PPO and delivery only			26,374				22,226				4,148				18.7	%
Total retail deliveries				94,807				93,356				1,451				1.6	%

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(a)		Full service reflects deliveries to customers taking electric generation service under tariffed rates.
(b)		Delivery only service reflects customers receiving electric generation service from an AES.

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			Nine Months Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	2,801			$	2,900			$	(99	)			(3.4	)%
Small commercial & industrial				1,819				1,874				(55	)			(2.9	)%
Large commercial & industrial				1,047				1,065				(18	)			(1.7	)%
Public authorities & electric railroads				284				309				(25	)			(8.1	)%
	Total full service			5,951				6,148				(197	)			(3.2	)%
PPO (ComEd only)(b)
Small commercial & industrial				184				174				10				5.7	%
Large commercial & industrial				163				199				(36	)			(18.1	)%
Public authorities & electric railroads				87				81				6				7.4	%
				434				454				(20	)			(4.4	)%
Delivery only(c)
Residential				131				52				79				151.9	%
Small commercial & industrial				169				160				9				5.6	%
Large commercial & industrial				140				149				(9	)			(6.0	)%
Public authorities & electric railroads				25				25				—				—
				465				386				79				20.5	%
	Total PPO and delivery only			899				840				59				7.0	%
Total electric retail revenues				6,850				6,988				(138	)			(2.0	)%
	Wholesale and miscellaneous revenue(d)			480				414				66				15.9	%
Total electric revenue			$	7,330			$	7,402			$	(72	)			(1.0	)%

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(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO’s tariffed rates also include a CTC.
(b)		Revenue from customers choosing the ComEd PPO includes an energy charge at market rates, transmission and distribution charges and a CTC.
(c)		Delivery only reflects revenue from customers receiving electric generation service from an AES. Revenue from customers choosing an AES includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from an AES were included in wholesale and miscellaneous revenue.
(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

     Energy Delivery’s gas sales statistics and revenue detail were as follows:

		Nine Months Ended
		September 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			41,831				44,183				(2,352	)			(5.3	)%
Transportation			19,709				19,954				(245	)			(1.2	)%
Total			61,540				64,137				(2,597	)			(4.0	)%

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			Nine Months Ended
			September 30,
Revenue			2004				2003				Variance				% Change
Retail sales			$	485			$	418			$	67				16.0%
Transportation				13				14				(1	)			(7.1	)%
Resales and other				25				16				9				56.3%
	Total		$	523			$	448			$	75				16.7%

	Results of Operations — Generation

      As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, Exelon Energy Company’s results of operations have been included within Generation’s results of operations as if this transfer had occurred on January 1, 2003 within this segment analysis.

		Nine Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	6,153			$	6,797			$	(644	)
Purchased power and fuel expense			3,252				4,535				1,283
Impairment of Boston Generating, LLC long-lived assets			—				945				945
Operating and maintenance expense			1,645				1,410				(235	)
Depreciation and amortization			218				142				(76	)
Operating income (loss)			901				(353	)			1,254
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles			900				(566	)			1,466
Income (loss) before cumulative effect of changes in accounting principles			567				(351	)			918
Cumulative effect of changes in accounting principles			32				108				(76	)
Net income (loss)			599				(243	)			842

      Operating Revenues. For the nine months ended September 30, 2004 and 2003, Generation’s sales were as follows:

		Nine Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates		$	2,924			$	3,030			$	(106	)			(3.5	)%
Wholesale and retail electric sales			2,501				2,908				(407	)			(14.0	)%
Total energy sales revenue			5,425				5,938				(513	)			(8.6	)%
Retail gas sales			315				467				(152	)			(32.5	)%
Trading portfolio			(2	)			(1	)			(1	)			100.0	%
Other revenue(a)			415				393				22				5.6	%
Total revenue		$	6,153			$	6,797			$	(644	)			(9.5	)%

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(a)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful

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		Nine Months Ended
		September 30,
Sales (in GWhs)		2004(a)				2003				Variance				% Change
Electric sales to affiliates			83,637				86,242				(2,605	)			(3.0	)%
Wholesale and retail electric sales			70,853				84,913				(14,060	)			(16.6	)%
Total sales			154,490				171,155				(16,665	)			(9.7	)%

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(a)		Sales in 2004 do not include 18,557 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.

     Trading volumes of 17,569 GWhs and 28,532 GWhs for the nine months ended September 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

      Generation’s average margin (operating revenue, less purchased power and fuel expenses) and other operating data for the nine months ended September 30, 2004 and 2003 were as follows:

			Nine Months
			Ended
			September 30,
($/MWh)			2004				2003				% Change
Average revenue
	Energy Delivery		$	34.96			$	35.13				(0.5	)%
	Market and retail electric sales			35.30				34.25				3.1	%
	Total — excluding the trading portfolio			35.12				34.69				1.2	%
Average supply cost(a) — excluding the trading portfolio			$	21.05			$	26.50				(20.6	)%
Average margin — excluding the trading portfolio			$	14.07			$	8.19				71.8	%

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(a)		Average supply cost includes purchased power, fuel costs and PPAs with AmerGen in 2003.

     Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11(a)		$	(715	)
Boston Generating			(159	)
AmerGen operations			148
Other			319
Decrease in wholesale and retail electric sales		$	(407	)

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(a)		Does not include $9 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

     The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 decreased wholesale and retail sales, which was partially offset by the increase from the acquisition of the remaining 50% of AmerGen in 2003.

      The remaining increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market as a result of forward hedging and fuel prices. Higher average market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven higher primarily by higher oil and gas prices.

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      Electric Sales to Affiliates. The decrease in revenue from affiliates included $97 million in lower sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to customers purchasing energy from an AES and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.

      Retail Gas Sales. Retail gas sales decreased $152 million as a result of the wind down of Exelon Energy’s northeast business.

      Other. Certain other revenues increased for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004.

	Purchased Power and Fuel Expense

      Generation’s supply source is summarized below:

		Nine Months Ended
		September 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			102,968				89,102				13,866				15.6	%
Purchases — non-trading portfolio(b)			37,158				64,012				(26,854	)			(42.0	)%
Fossil and hydroelectric generation			14,364				18,041				(3,677	)			(20.4	)%
Total supply			154,490				171,155				(16,665	)			(9.7	)%

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(a)		Excludes AmerGen in 2003. AmerGen generated 14,912 GWhs during the nine months ended September 30, 2004.
(b)		18,557 GWhs were netted with purchased power GWhs in 2004 as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes retail electric sales of Exelon Energy in both periods.

     The changes in Generation’s purchased power and fuel expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11		$	(724	)
AmerGen			(284	)
Midwest Generation			(110	)
Boston Generating			(103	)
Mark-to-market adjustments on hedging activity			(57	)
Price			(31	)
Volume			181
Sithe			113
Other			(268	)
Decrease in purchased power and fuel expense		$	(1,283	)

      Effects of the Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $724 million.

      AmerGen. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $284 million, which had a significant impact on Generation’s average supply cost decrease for the same period. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense.

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      Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due to the sale of the business in May of 2004.

      Hedging Activity. Mark-to-market gains on hedging activities were $39 million for the nine months ended September 30, 2004 compared to losses of $18 million for the same period in 2003.

      Price. The decrease primarily reflects lower average fossil fuel costs of $31 million during the nine months ended September 30, 2004 as compared to the same period in 2003.

      Volume. Generation experienced increased purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

      Sithe. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.

      Other. Other decreases in purchased power and fuel were primarily due to $168 million of lower fuel expense due to the wind down of Exelon Energy’s northeast business, $66 million in lower transmission expense resulting from reduced inter-region transmission as a result of ComEd’s integration into PJM in the second quarter of 2004, and $16 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

      Impairment of the Long-Lived Assets of Boston Generating. In connection with the decision to transition out of the ownership of Boston Generating and the projects during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes) in the third quarter of 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

      Operating and Maintenance Expense. The changes in operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
AmerGen(a)		$	266
Sithe Energies, Inc.			40
Refueling outage costs			28
Boston Generating			14
Pension, payroll and benefit costs associated with The Exelon Way			(68	)
DOE settlement(b)			(52	)
Other			7
Increase in operating and maintenance expense		$	235

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(a)		Includes refueling outage expense of $24 million at AmerGen.
(b)		See Note 15 of the Combined Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement reached with the DOE.

     The increase in operating and maintenance expense was primarily due to the inclusion of AmerGen and Sithe’s operating results in Generation’s consolidated results for 2004. This increase was partially offset with reductions in payroll-related costs due to implementation of the programs associated with The Exelon Way,

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      Nuclear fleet operating data and purchased power costs data for the nine months ended September 30, 2004 and 2003 were as follows:

		Nine Months
		Ended
		September 30,
		2004				2003
Nuclear fleet capacity factor(a)			94.1	%			94.5	%
Nuclear fleet production cost per MWh(a)		$	11.99			$	12.16
Average purchased power cost for wholesale operations per MWh(b)		$	49.11			$	45.42

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(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).
(b)		Includes PPAs with AmerGen in 2003.

     Lower nuclear capacity factors were primarily due to 51 additional planned refueling outage days, resulting in a $34 million increase in planned outage costs in the nine months ended September 30, 2004 as compared to the same period in 2003. There were six planned outages during the nine months ended September 30, 2004, compared to five planned outages during the same period in 2003. The nine months ended September 30, 2004 included 16 unplanned outages compared to 20 unplanned outages during the same period in 2003.

      The lower nuclear production costs were primarily due to the spent fuel storage cost settlement agreement with the DOE which resulted in the reimbursement of $40 million in spent fuel storage costs incurred as operating and maintenance expenses prior to September 30, 2003, and the recording of $12 million of spent fuel storage operating and maintenance expenses incurred from October 1, 2003 to September 30, 2004 as an Other Account Receivable.

      Nuclear capacity factors were also affected by Quad Cities operating at lower than anticipated capacity levels. The Quad Cities units have intermittently been operating at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.

      Depreciation and Amortization. The increase in depreciation and amortization expense for the nine months ended September 30, 2004 as compared to the same period in 2003 was primarily due to the establishment of an ARC asset for retired nuclear units of $36 million associated with the third quarter 2004 update of the nuclear decommissioning ARO. This ARC was immediately impaired through depreciation expense as this asset was associated with retired nuclear units that do not have any remaining useful life. The remaining increase was due to capital additions and the consolidation of Sithe and AmerGen. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities that were sold in May 2004.

      Effective Income Tax Rate. The effective income tax rate was 38% for the nine months ended September 30, 2004 compared to 38% for the same period in 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

      Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles recorded during the nine months ended September 30, 2004 and 2003 included $32 million, net of income taxes, recorded in 2004 related to the consolidation of Sithe pursuant to FIN No. 46-R, which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, and income of $108 million, net of income taxes, recorded in 2003 related to the adoption of SFAS No. 143. See Note 2 of the Combined Notes to Consolidated Financial Statements for further discussion of these effects.

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	Results of Operations — Enterprises

      As previously described, effective January 1, 2004, Exelon contributed its interest in Exelon Energy Company to Generation. Exelon Energy Company was previously reported as a part of the Enterprises segment. For comparative discussion and analysis, the results of Exelon Energy Company have been excluded from Enterprises’ 2003 results of operations discussed below.

		Nine Months
		Ended
		September 30,								Favorable
										(Unfavorable)
		2004				2003				Variance
Operating revenues		$	148			$	808			$	(660	)
Operating and maintenance expense			189				822				633
Operating loss			(46	)			(42	)			(4	)
Other income and deductions			55				(37	)			92
Income (loss) from continuing operations before income taxes and cumulative effect of changes in accounting principles			9				(79	)			88
Loss before cumulative effect of changes in accounting principles			—				(50	)			50
Net income (loss)			(9	)			(51	)			42

      Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. See the discussion of Enterprises’ results of operations for the three months ended September 30, 2004 compared to the three months ended September 30, 2003 for a description of divestitures that affect the comparability of results between periods.

      Operating Revenues. The changes in Enterprises’ operating revenues for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
InfraSource businesses		$	(394	)
Services(a)			(169	)
F & M Holdings, LLC(b)			(87	)
Other			(10	)
Decrease in operating revenues		$	(660	)

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(a)		Primarily due to the sale of certain businesses.
(b)		For the remaining businesses of F&M Holdings, LLC, operating revenues decreased as a result of the sale of certain businesses and wind-down efforts.

     Operating and Maintenance Expense. The changes in Enterprises’ operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
InfraSource businesses		$	(418	)
Services(a)			(146	)
F & M Holdings, LLC			(78	)
Other			9
Decrease in operating and maintenance expense		$	(633	)

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(a)		Primarily due to the sale of certain businesses.
(b)		For the remaining businesses of F&M Holdings, LLC, operating and maintenance expense decreased as a result of the sale of certain businesses and wind-down efforts.

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     Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sale of Thermal and Enterprises’ investment in PECO Telcove of $54 million (before income taxes and net of debt prepayment penalties) and income of $18 million recorded during the second quarter of 2004 related to the collection of a note receivable prior to its maturity. Other income and deductions in 2003 included impairment charges of energy, software and communications investments of $40 million.

      Effective Income Tax Rate. The effective income tax rate was 100% for the nine months ended September 30, 2004 compared to 37% for the same period in 2003. The increase in the effective tax rate was primarily attributable to the state tax impact of the sale of certain Capital Partners investments and the PECOTelcove transactions.

Liquidity and Capital Resources

      Exelon’s businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery’s and Generation’s operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing at 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 where Exelon no longer has access to the capital markets at reasonable terms, Exelon has access to revolving credit facilities with aggregate bank commitments of $1.5 billion that it currently utilizes to support its commercial paper programs. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion. Exelon primarily uses its capital resources to fund capital requirements, including construction, to retire debt, to pay common stock dividends, to fund its pension obligations and to invest in new and existing ventures. Future acquisitions that Exelon may undertake may require external financing, which might include issuing Exelon common stock.

	Cash Flows from Operating Activities

      Energy Delivery’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are

      Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future. 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 Exelon’s ability to fund its business requirements.

      Cash flows from operations for the nine months ended September 30, 2004 and 2003 were $3,154 million and $2,553 million, respectively. Changes in Exelon’s cash flows from operations are generally consistent with changes in its results of operations, and further adjusted by changes in working capital in the normal course of business.

      In addition to the items mentioned in “Results of Operations,” the following items affected Exelon’s operating cash flows for the nine months ended September 30, 2004 and 2003:

	•	At September 30, 2004, Exelon was in a net Federal income tax receivable position as compared to a net Federal income tax payable position at September 30, 2003. Comparability of the cash flows for the two periods is affected significantly by this change in the Federal income tax position. The primary driver of the increase in cash from the changes in receivables during the nine months ended September 30, 2004 was the Federal income tax provision of approximately $289 million and the

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		receipt of a $150 million Federal income tax refund during 2004, completely offset by the payment of approximately $150 million of Federal income taxes.
	•	In addition to the effects of the changes in Federal income taxes, cash flows from customer accounts receivables decreased $68 million and $18 million, net of uncollectible accounts written-off of $73 million and $83 million, respectively, during the nine months ended September 30, 2004 and 2003, respectively. The primary driver of the year-over-year change in customer receivables was the unfavorable weather in Energy Delivery’s service territories in the current year.
	•	Natural gas inventories increased $15 million and deferred natural gas costs decreased $52 million during the nine months ended September 30, 2004 resulting in a $37 million increase to operating cash flows. During 2003, an increase in natural gas inventories of $44 million and an increase in deferred natural gas costs of $33 million resulted in a $77 million decrease to operating cash flow. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. During 2004, PECO was recovering fuel revenues from customers in excess of gas costs being incurred. During 2003, PECO was incurring gas costs in excess of fuel revenues being recovered from customers.
	•	An increase in required deposits for energy trading activity of $51 million resulted from Generation exceeding its negotiated credit positions with counterparties during the nine months ended September 30, 2003. During 2004, required deposits for trading activity resulted in a $59 million net cash inflow.
	•	Discretionary tax-deductible pension plan payments were $426 million for the nine months ended September 30, 2004 compared to $367 million for the same period in 2003. Exelon also contributed $8 million during 2004 to the pension plans needed to satisfy minimum funding requirements of the Employee Retirement Income Security Act. Additionally, $55 million and $50 million were contributed to the postretirement welfare benefit plans for the nine months ended September 30, 2004 and 2003, respectively. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits.
	•	During the third quarter of 2004, Exelon paid $63 million for call premiums on the retirement of ComEd debt. See “Cash Flows from Financing Activities” for further information regarding debt retirements pursuant to the accelerated liability management plan.

      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, 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to the Consolidated Balance Sheets of ComEd and the remainder to the Consolidated Balance Sheets of Generation. The 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of Exelon. Exelon’s management believes Exelon’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5). However, the ultimate outcome of such matters could result in unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.

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	Cash Flows from Investing Activities

      Cash flows used in investing activities for the nine months ended September 30, 2004 and 2003 were $1,178 million and $1,223 million, respectively. Cash used in investing activities in 2004 compared to cash used in investing activities in 2003 was primarily attributable to the following:

	•	Cash proceeds of $212 million, net of transaction costs and contingency payments on prior year dispositions, were received during the nine months ended September 30, 2004 from the sales of Thermal, substantially all of the operating components of Services and Enterprises’ investments in PECO TelCove and other equity method investments. Additionally, cash proceeds of $24 million were received during the nine months ended September 30, 2004 from the sale of certain businesses of Sithe. In September 2003, Exelon received approximately $175 million of cash proceeds from the sale of InfraSource.
	•	Cash proceeds of $42 million were received from the sale of three gas turbines at Generation that were classified as assets held for sale at December 31, 2003.
	•	Capital expenditures decreased $114 million net of the settlement of litigation with the DOE of $20 million and liquidating damages of $92 million received in 2003.
	•	Net investments in nuclear decommissioning trust funds increased $39 million.
	•	On March 31, 2004, Exelon consolidated the assets and liabilities of Sithe under the provisions of FIN No. 46-R, which resulted in an increase in cash of $19 million. See Note 2 and Note 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the FIN No. 46-R consolidation of Sithe.
	•	Early settlement on an acquisition note receivable from the 2003 disposition of InfraSource resulted in cash proceeds of $30 million during the nine months ended September 30, 2004.
	•	Collection of a $20 million note receivable during 2004 related to the sale of certain businesses of Sithe during the fourth quarter of 2003 and the first quarter of 2004.

      Capital expenditures by business segment for the nine months ended September 30, 2004 and 2003 were as follows:

		Nine Months
		Ended
		September 30,
		2004				2003
Energy Delivery		$	680			$	728
Generation(a)			608				641
Enterprises			—				19
Corporate and other			7				21
Total capital expenditures		$	1,295			$	1,409

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(a)		Net of liquidating damages of $92 million in 2003.

     Energy Delivery’s capital expenditures for the nine months ended September 30, 2004 reflected continuing efforts to improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. ComEd estimates that it will spend up to approximately $690 million in total capital expenditures for 2004. This represents an increase of approximately $75 million more than had been previously planned, primarily as a result of expansion of the ComEd distribution system to support new business and customer growth. However, Exelon is continuing to evaluate its total capital spending requirements and potential mitigating opportunities. Exelon anticipates that Energy Delivery’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities or capital contributions from Exelon.

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      Generation’s capital expenditures for the nine months ended September 30, 2004 reflected additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Capital expenditures were reduced by the settlement agreement with the DOE which resulted in the reimbursement of $12 million in spent fuel storage costs incurred as capital expenses prior to September 30, 2003, and the recording of $8 million of spent fuel storage capital expenses incurred from October 1, 2003 to September 30, 2004 within Accounts receivable, other. Generation’s capital expenditures for the nine months ended September 30, 2003 reflected the construction of the Mystic 8 and 9 and Fore River Boston Generating facilities. During 2003, Boston Generating received $92 million of liquidated damages from Raytheon Company (Raytheon) as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon’s construction of these generating facilities. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, Generation’s borrowings or capital contributions from Exelon.

	Cash Flows from Financing Activities

      Cash flows used in financing activities for the nine months ended September 30, 2004 were $1,885 million compared to $1,183 million for the same period in 2003. The increase in cash used in financing activities was primarily attributable to the retirement of $768 million of long-term debt during the nine months ended September 30, 2004 in accordance with an accelerated liability management plan and the retirement of $547 million of long-term debt due to financing affiliates. During the nine months ended September 30, 2003, Exelon issued debt (net of retirements during the period) and preferred stock of approximately $33 million. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding debt issuances and retirements during the nine months ended September 30, 2004. During the nine months ended September 30, 2004, Exelon repaid $1 million of commercial paper and received cash proceeds of $31 million from the settlement of interest-rate swaps. During the nine months ended September 30, 2003, Exelon repaid $599 million of commercial paper and paid $45 million to settle interest-rate swaps. Additionally, Exelon purchased treasury shares totaling $75 million during 2004 and received proceeds from employee stock plans of $192 million and $139 million for the nine months ended September 30, 2004 and 2003, respectively.

      The cash dividend payments on common stock for the nine months ended September 30, 2004 increased $104 million over the nine months ended September 30, 2003, reflecting a 10% increase in the first quarter of 2004 and an 11% increase in the third quarter of 2004. On July 27, 2004, the Exelon Board of Directors approved a policy of targeting a dividend payout ratio of 50 to 60% of ongoing earnings beginning in 2005. The actual dividend payout rate depends on Exelon achieving its objectives, including meeting planned cash flow targets and strengthening its balance sheet. On October 19, 2004, the Exelon Board of Directors approved an increased dividend of $0.40 per share, payable to shareholders of record as of November 15, 2004. This dividend increase is consistent with the dividend policy approved in July 2004. The Board of Directors must approve the dividends each quarter after review of Exelon’s financial condition at the time.

      From time to time and as market conditions warrant, Exelon may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Exelon’s balance sheet. In the third quarter of 2004, Exelon initiated an accelerated liability management plan at ComEd that targets the elimination of $1.2 billion of debt from ComEd’s balance sheet by the end of 2004. Through September 30, 2004, ComEd had retired approximately $768 million of debt under the plan and intends to retire over $400 million of long-term debt in the fourth quarter of 2004 to complete the accelerated liability management plan.

	Credit Issues

      Exelon Credit Facility. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. At December 31, 2003, Exelon Corporate, along with ComEd, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million

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		Bank				Available				Outstanding
Borrower		Sublimit(a)				Capacity(b)				Commercial Paper
Exelon Corporate		$	700			$	689			$	325
ComEd			250				224				—
PECO			100				100				—
Generation			450				271				—

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(a)		Sublimits under the credit agreements can change upon written notification to the bank group.
(b)		Available capacity represents primarily the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the Exelon Credit Facility.

     Interest rates on the advances under the credit facility are based on either 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 or prime. The maximum LIBOR adder would be 132 basis points. For the nine months ended September 30, 2004, the average interest rate on notes payable was approximately 1.19%.

      The credit agreements require Exelon Corporate, ComEd, PECO and Generation 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 Corporate and Generation, revenues from Exelon New England Holding Company, LLC (Exelon New England) and Sithe and interest on the debt of their project subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve-month period ended September 30, 2004:

Exelon Corporate

ComEd

PECO

Generation

Credit agreement threshold

2.65 to 1

2.25 to 1

2.25 to 1

3.25 to 1

      At September 30, 2004, each of Exelon Corporate, ComEd, PECO and Generation were in compliance with the foregoing thresholds.

      Capital Structure. At September 30, 2004, the capital structures of Exelon, ComEd, PECO and Generation consisted of the following:

		Exelon
		Consolidated				ComEd(a)				PECO(a)				Generation
Long-term debt			35	%			30	%			22	%			42	%
Long-term debt to affiliates(b)			23				15				59				—
Common equity			40				55				18				—
Member’s equity			—				—				—				57
Preferred securities			1				—				1				—
Notes payable			1				—				—				—
Minority interest			—				—				—				1

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(a)		At September 30, 2004, ComEd’s capital structure, excluding the deduction from shareholders’ equity of the $156 million receivable from Exelon (which amount is deducted for GAAP purposes, as reflected in the table, but is excluded from the percentages in this footnote) to reflect amounts expected to be received by ComEd from Exelon to pay future taxes, consisted of 30% long-term debt, 14% long-term debt to affiliates and 56% common equity. Likewise, PECO’s capital structure, excluding the deduction from shareholder’s equity of the $1.5 billion receivable

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		from Exelon, consisted of 34% common equity, 1% preferred securities and 65% long-term debt, including long-term debt to unconsolidated affiliates.
(b)		Includes $6 billion, $2 billion and $4 billion owed to unconsolidated affiliates of Exelon, ComEd and PECO, respectively, that qualify as special purpose entities under FIN No. 46-R. These special purpose entities were created for the sole purpose of issuing debt obligations to securitize intangible transition property and CTCs of Energy Delivery or mandatorily redeemable preferred securities. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding FIN No. 46-R.

     Boston Generating Project Debt. Boston Generating had a $1.25 billion credit facility (Boston Generating Credit Facility), which was entered into primarily to finance the development and construction of the Mystic 8 and 9 and Fore River generating facilities. On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of Boston Generating to a special purpose entity owned by the lenders under the Boston Generating Credit Facility. Accordingly, the Boston Generating Credit Facility was eliminated from the consolidated financial statements of Exelon and Generation during the second quarter of 2004.

      See Note 3 of the Combined Notes to Consolidated Financial Statements for information regarding the sale of Generation’s ownership interest in Boston Generating to the lenders under the Boston Generating Credit Facility.

      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. Participation in the money pool is subject to authorization by Exelon’s corporate treasurer. ComEd and its subsidiary, Commonwealth Edison of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and Unicom Investment, Inc., a wholly owned subsidiary of Exelon, may participate as lenders. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. Maximum amounts invested in and borrowed from the money pool by participant during the nine months ended September 30, 2004 are described in the following table in addition to the net investment or borrowing as of September 30, 2004:

		Maximum				Maximum				September 30, 2004
		Invested				Borrowed				Contributed (Borrowed)
ComEd		$	487			$	17			$	(17	)
ComEd of Indiana			21				—				21	(a)
PECO			162				36				26
Generation			17				546				17
BSC			—				197				(125	)
Unicom Investments			160				—				99

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(a)		The activity at ComEd of Indiana at September 30, 2004 was eliminated in the consolidation of ComEd.

     Sithe Long-Term Debt. At September 30, 2004, $836 million of Sithe’s long-term debt, including current maturities, was included in Exelon and Generation’s Consolidated Balance Sheets. See Note 2 and Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding the consolidation of Sithe and see Note 9 of the Combined Notes to Consolidated Financial Statements for information regarding Sithe’s long-term debt and the annual maturities.

      Security Ratings. Exelon’s access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered its rating on PECO’s First Mortgage Bonds from A to A-. None of the other securities ratings of Exelon, PECO or Exelon’s other subsidiaries has changed from those set forth in the 2003 Form 10-K. None of Exelon’s borrowings is subject to default or

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      Shelf Registration. As of September 30, 2004, Exelon, ComEd and PECO have current effective shelf registration statements for the sale of $2.0 billion, $555 million and $550 million, respectively, of securities. The ability of Exelon, ComEd or PECO to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.

      PUHCA Restrictions. On April 1, 2004, Exelon obtained an order from the SEC under the Public Utilities Holding Company Act of 1935 (PUHCA) authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for Exelon Corporate and Generation at December 31, 2003 with no separate sublimit for short-term debt. The 2004 order replaced a prior SEC order that expired on March 31, 2004 that had authorized up to $4.0 billion of financing. No securities have been issued under the above described limit. The prior order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. The 2004 order gives Exelon an additional $1.5 billion of guaranty authority. At September 30, 2004, Exelon had provided $2.1 billion of guarantees pursuant to SEC authorization. See “Contractual Obligations and Off-Balance Sheet Arrangements” in this section for further discussion of guarantees. The SEC order requires Exelon to maintain a ratio of common equity to total capitalization (including securitization debt) of not less than 30%. At September 30, 2004, Exelon’s common equity ratio was 40%. Exelon expects that it will maintain a common equity ratio of at least 30%.

      Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4.0 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At September 30, 2004, Exelon had invested $2.1 billion in EWGs, leaving $1.9 billion of investment authority under the order. In its April 1, 2004 financing order, the SEC authorized Exelon to invest $4 billion in EWGs and reserved jurisdiction over an additional $3.0 billion in investments in EWGs.

      Under applicable law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon. At September 30, 2004, Exelon had retained earnings of $3.3 billion, including ComEd’s retained earnings of $1,075 million (of which $1,078 million had been appropriated for future dividend payments), PECO’s retained earnings of $639 million and Generation’s undistributed earnings of $1,031 million.

	Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

      Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Exelon’s, ComEd’s, PECO’s and Generation’s contractual obligations and commercial commitments as of September 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

	•	Generation acquired a $50 million letter of credit to support the contractual obligations of Sithe and its subsidiaries and issued a $45 million of letter of credit for Power Team to cover collateral calls that had previously been met with cash collateral.
	•	On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call is subject to state and Federal regulatory approvals.
	•	See Note 9 and Note 19 to the Combined Notes to Consolidated Financial Statements for discussion of material changes in the registrants’ respective debt from the amounts set forth in the 2003 Form 10-K.

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COMMONWEALTH EDISON COMPANY

General

      ComEd operates in a single business segment and its operations consist of the regulated sale of electricity and distribution and transmission services in northern Illinois.

Executive Overview

      Financial Results. ComEd’s net income for the three months ended September 30, 2004 decreased 24% as compared to the same period in 2003 primarily due to losses recorded due to the extinguishment of debt in 2004.

      ComEd experienced an overall decline in net income of 9% during the nine months ended September 30, 2004. This decline primarily reflects lower collections of CTCs and losses recorded due to the extinguishment of debt in 2004, partially offset by lower operating and maintenance expense compared to the corresponding period in 2003 in which ComEd recorded charges associated with an agreement with various Illinois retail market participants and other interested parties and due to a decrease in severance and severance-related charges associated with The Exelon Way in 2004.

      The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K for a discussion of ComEd’s implementation of The Exelon Way.

      Financing Activities. In 2004, ComEd redeemed and retired $768 million of outstanding debt pursuant to an accelerated liability management plan and repaid $30 million of other long-term debt. ComEd also made scheduled payments of $261 million on its long-term debt to ComEd Transitional Funding Trust. ComEd plans to retire over $400 million of long-term debt in the fourth quarter of 2004 to complete the accelerated liability management plan. ComEd met its capital resource commitments primarily with internally generated cash, a return of investments in the intercompany money pool and the repayment of intercompany receivables. When necessary, ComEd obtains funds from external sources, including the capital markets, the intercompany money pool and through bank borrowings.

      Regulatory Developments — PJM Integration. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations, including a provision to hold certain utilities in Michigan and Wisconsin harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004. In October 2004, ComEd has entered into settlement agreements with nearly all the Michigan parties calling for a payment of approximately $2 million by ComEd. The agreements have been filed with the FERC and are awaiting approval. Settlement talks continue between ComEd and the remaining Wisconsin parties.

      PECO and ComEd’s membership in PJM supports Exelon’s commitment to competitive wholesale electric markets and will provide Exelon the benefits of more transparent, liquid and competitive markets for the sale and purchase of electric energy and capacity. Upon joining PJM, ComEd began incurring administrative fees, which are expected to approximate $30 million annually. ComEd believes such costs will ultimately be partially offset by the benefits of full access to a wholesale competitive marketplace and increased revenue requirements, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on ComEd.

      Through and Out Proceeding. ComEd currently recognizes approximately $66 million of annual revenue from T&O rates for energy flowing across ComEd’s transmission system. On March 19, 2004, the FERC issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM, the Midwest ISO and other parties filed various pricing proposals with the FERC on or before October 1, 2004, with an effective

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      Rate Design Proceeding. Additionally, certain PJM transmission owners, including ComEd, are subject to a rate design proceeding before the FERC. One or more filings will be made in January 2005 to address, among other items, how costs associated with new investments should be recovered. ComEd is presently evaluating the extent to which it will participate in this proceeding.

      At this early stage, ComEd cannot predict the outcome of either of the above proceedings; however, these proceedings could lead to adverse impacts on the results of operations of ComEd.

      Delivery Services Rates. On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders, which are now final, that effectuated an agreement (Agreement) with various Illinois retail market participants and other interested parties that settled, among other things, delivery service rates and the market value index proceeding and facilitates competitive service declarations for large-load customers and an extension of the PPA with Generation.

      Competitive Service Declaration. On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its provider of last resort obligation to be the back-up energy supplier at market-based rates for customers with energy demands of at lease three megawatts. About 370 of ComEd’s largest energy customers are affected, representing an aggregate supply obligation or load of approximately 2,500 megawatts. These customers accounted for 10% of ComEd’s 2003 MWh deliveries. These customers will not have a right to take bundled service after June 2006 or to come back to bundled rates if they choose an alternative supplier prior to June 2006. The parties to the March 2003 Agreement have committed, if specified market conditions exist, not to oppose a process for achieving a similar competitive declaration for customers having energy demands of one to three megawatts. To date, ComEd has not requested the competitive declaration for this second set of customers but continues to evaluate its options.

      On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff, to be available to customers who choose not to go to the competitive market to procure their electric power and energy. An appeal to each of the ICC’s orders was filed. On March 24, 2004, the Illinois Appellate Court issued its opinion affirming the ICC’s orders in both cases. The Court found that the ICC properly allowed ComEd’s competitive declaration for customers with loads of more than 3 MWs to go into effect and that the ICC’s order approving the hourly rate was lawful.

      Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and hearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. During the third quarter of 2004, a settlement agreement was reached and approved by the FERC, on an interim basis, which established new wholesale rates that became effective May 1, 2004. The FERC has allowed the proposed rates in the settlement agreement pending the final approval by the FERC. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to have a significant effect on operating revenues until after December 31, 2006.

      Outlook for the Remainder of 2004 and Beyond. ComEd’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd — Executive Summary” in the 2003 Form 10-K.

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Results of Operations

	Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

				Three Months
				Ended
				September 30,								Favorable
												(Unfavorable)
				2004				2003				Variance
Operating revenues				$	1,720			$	1,737			$	(17	)
Operating expenses
	Purchased power				907				891				(16	)
	Operating and maintenance				231				299				68
	Depreciation and amortization				104				97				(7	)
	Taxes other than income				68				87				19
		Total operating expense			1,310				1,374				64
Operating income					410				363				47
Other income and deductions
	Interest expense				(86	)			(107	)			21
	Distributions on mandatorily redeemable preferred securities				—				(6	)			6
	Equity in losses of unconsolidated affiliates				(4	)			—				(4	)
	Net loss on extinguishment of long-term debt				(106	)			—				(106	)
	Other, net				5				15				(10	)
		Total other income and deductions			(191	)			(98	)			(93	)
Income before income taxes					219				265				(46	)
Income taxes					95				102				7
Net income				$	124			$	163			$	(39	)

119

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	Operating Revenues

      ComEd’s electric sales statistics were as follows:

			Three Months
			Ended
			September 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				7,434				8,197				(763	)			(9.3	)%
Small commercial & industrial				5,309				5,749				(440	)			(7.7	)%
Large commercial & industrial				1,498				1,539				(41	)			(2.7	)%
Public authorities & electric railroads				1,213				1,269				(56	)			(4.4	)%
	Total full service			15,454				16,754				(1,300	)			(7.8	)%
PPO
Small commercial & industrial				1,053				884				169				19.1	%
Large commercial & industrial				1,160				896				264				29.5	%
Public authorities & electric railroads				562				428				134				31.3	%
				2,775				2,208				567				25.7	%
Delivery only(b)
Small commercial & industrial				1,874				1,721				153				8.9	%
Large commercial & industrial				3,086				2,934				152				5.2	%
Public authorities & electric railroads				371				426				(55	)			(12.9	)%
				5,331				5,081				250				4.9	%
	Total PPO and delivery only			8,106				7,289				817				11.2	%
Total retail deliveries				23,560				24,043				(483	)			(2.0	)%

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(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 AES.

120

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			Three Months
			Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	699			$	760			$	(61	)			(8.0	)%
Small commercial & industrial				463				487				(24	)			(4.9	)%
Large commercial & industrial				76				82				(6	)			(7.3	)%
Public authorities & electric railroads				77				82				(5	)			(6.1	)%
	Total full service			1,315				1,411				(96	)			(6.8	)%
PPO(b)
Small commercial & industrial				76				65				11				16.9	%
Large commercial & industrial				71				56				15				26.8	%
Public authorities & electric railroads				33				26				7				26.9	%
				180				147				33				22.4	%
Delivery only(c)
Small commercial & industrial				35				34				1				2.9	%
Large commercial & industrial				41				41				—				—
Public authorities & electric railroads				8				8				—				—
				84				83				1				1.2	%
Total PPO and delivery only				264				230				34				14.8	%
Total electric retail revenues				1,579				1,641				(62	)			(3.8	)%
Wholesale and miscellaneous revenue(d)				141				96				45				46.9	%
Total electric revenue			$	1,720			$	1,737			$	(17	)			(1.0	)%

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(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.
(b)		Revenue from customers choosing the ComEd PPO includes an energy charge at market rates, transmission and distribution charges and a CTC charge.
(c)		Delivery only revenue from customers choosing an AES includes a distribution charge and a CTC charge. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from AES were included in wholesale and miscellaneous revenue.
(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

121

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     The changes in electric retail revenues for the three months ended September 30, 2004, as compared to the same period in 2003, are attributable to the following:

			Increase
			(Decrease)
Weather			$	(118	)
Customer choice				(6	)
Volume				52
Rate changes				11
Other				(1	)
	Electric retail revenue			(62	)
PJM Transmission				63
Other				(18	)
	Wholesale and miscellaneous revenue			45
	Total decrease in electric retail revenue		$	(17	)

      Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather conditions for the three months ended September 30, 2004 were unfavorable compared to the same period in 2003. Cooling degree-days decreased 27% for the three months ended September 30, 2004 compared to the same period in 2003, and were 30% lower than normal. Heating degree-days decreased 24% for the three months ended September 30, 2004 compared to the same period in 2003, and were 30% lower than normal.

      Customer Choice. All ComEd customers have the choice to purchase energy from an AES. This choice generally does not affect the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd. As of September 30, 2004, no AES has approval from the ICC, and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity.

      For the three months ended September 30, 2004, the energy provided by AESs was 5,331 GWhs, or 23%, as compared to 5,081 GWhs, or 21%, for the same period in 2003.

      The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of September 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,600 as compared to 20,000 as of the same period in 2003, representing less than 1% of total customers in each period. However, MWhs delivered to such customers increased from approximately 7.3 million for the three months ended September 30, 2003 to 8.1 million for three months ended September 30, 2004, or from 30% to 34% of total quarterly retail deliveries.

      Volume. Revenues from higher delivery volume, exclusive of weather, increased $52 million due to an increased number of customers and increased usage per customer, primarily residential and large and small commercial and industrial.

      Rate Changes. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. ComEd’s CTC revenues decreased $11 million for the three months ended September 30, 2004 as compared to the same period in 2003. This decrease was offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $11 million.

      Increased average rates paid by residential customers resulted in a $10 million increase. Although residential rates are frozen through 2006, average residential rates fluctuate due to the usage patterns of customers.

122

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      PJM Transmission. ComEd’s transmission revenues and purchased power expense each increased by $63 million in the three months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. The increase relates to the change in control of the transmission assets from ComEd to PJM whereby ComEd receives revenues for its proportionate share of the transmission revenues generated by PJM, but also pays PJM for the use of its transmission assets. For 2004, ComEd’s operating revenues are estimated to increase by approximately $180 million, offset by a corresponding and equal increase in purchased power expense. Starting in 2005, on an annual basis, ComEd’s operating revenues and purchased power expense are estimated to increase between $200 to $250 million; however, there is no expected impact on revenues net of purchased power expense.

	Purchased Power

      The increase in purchased power expense was primarily attributable to an increase of $28 million due to higher volume offset by a $58 million decrease due to unfavorable weather conditions, a $6 million decrease due to the mix of average pricing related to ComEd’s PPA with Generation, and a $2 million decrease as a result of non-residential customers choosing to purchase energy from an AES. ComEd’s operating revenues and purchased power expense each increased by $63 million in the three months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.

	Operating and Maintenance

      The changes in operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Severance, pension and postretirement benefit costs associated with The Exelon Way		$	(48	)
FERC annual fees(a)			(11	)
Decreased payroll expense due to fewer employees(b)			(9	)
Decreased incremental storm costs			(8	)
Higher corporate allocations(c)			11
Contractors			10
Other			(13	)
Decrease in operating and maintenance expense		$	(68	)

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(a)		After joining PJM on May 1, 2004, ComEd is no longer charged annual fees by the FERC. PJM pays the annual FERC fees. This represents the reversal of annual FERC fees.
(b)		ComEd has fewer employees as a result of The Exelon Way terminations.
(c)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in ComEd comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

	Depreciation and Amortization

		Three Months
		Ended
		September 30,
										Increase
		2004				2003				(Decrease)
Depreciation expense		$	83			$	77			$	6
Recoverable transition costs amortization			12				12				—
Other amortization expense			9				8				1
Total depreciation and amortization		$	104			$	97			$	7

123

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      The increase in depreciation expense is primarily due to capital additions.

      Recoverable transition costs amortization remained constant in the three months ended September 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $97 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.

	Taxes Other Than Income

      Taxes other than income decreased for three months ended September 30, 2004 as compared to the same period in 2003 as a result of $8 million in 2003 for additional use tax payments and a 2004 refund of $8 million for Illinois Electricity Distribution Taxes.

	Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities

      The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities but records interest expense to affiliates related to ComEd’s obligations to the financing trusts.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      During the three months ended September 30, 2004, ComEd has $4 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.

	Net Loss on Extinguishment of Long-Term Debt

      In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt, of which $618 million was retired during the third quarter of 2004. During the three months ended September 30, 2004, ComEd recorded a charge of $106 million associated with the retirement of debt under the plan. The components of this charge included the following: $63 million related to prepayment premiums; $11 million related to net unamortized premiums, discounts and debt issuance costs; $23 million of losses on reacquired debt previously deferred as regulatory assets; and $9 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets.

	Other, Net

      The change in Other, net is primarily related to a $3 million gain on sale of investments in 2003 and $1 million decrease in interest income on the long-term receivable from Unicom Investments, Inc. as a result of a lower principal balance.

	Income Taxes

      The effective income tax rate was 43% for the three months ended September 30, 2004, compared to 39% for the three months ended September 30, 2003. The increase in the effective income tax rate was primarily attributable to adjustments to prior period income taxes in connection with the completion of the 2003 tax return. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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	Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

				Nine Months
				Ended
				September 30,								Favorable
												(Unfavorable)
				2004				2003				Variance
Operating revenues				$	4,458			$	4,522			$	(64	)
Operating expenses
	Purchased power				2,014				2,001				(13	)
	Operating and maintenance				669				781				112
	Depreciation and amortization				309				287				(22	)
	Taxes other than income				219				235				16
		Total operating expense			3,211				3,304				93
Operating income					1,247				1,218				29
Other income and deductions
	Interest expense				(288	)			(322	)			34
	Distributions on mandatorily redeemable preferred securities				—				(20	)			20
	Equity in losses of unconsolidated affiliates				(13	)			—				(13	)
	Net loss on extinguishment of long-term debt				(106	)			—				(106	)
	Other, net				22				48				(26	)
		Total other income and deductions			(385	)			(294	)			(91	)
Income before income taxes and cumulative effect of a change in accounting principle					862				924				(62	)
Income taxes					351				365				14
Net income before cumulative effect of a change in accounting principle					511				559				(48	)
Cumulative effect of a change in accounting principle					—				5				(5	)
Net income				$	511			$	564			$	(53	)

125

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	Operating Revenues

      ComEd’s electric sales statistics were as follows:

			Nine Months
			Ended
			September 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				20,240				20,246				(6	)			—
Small commercial & industrial				15,233				16,490				(1,257	)			(7.6	)%
Large commercial & industrial				4,269				4,706				(437	)			(9.3	)%
Public authorities & electric railroads				3,653				4,018				(365	)			(9.1	)%
	Total full service			43,395				45,460				(2,065	)			(4.5	)%
PPO
Small commercial & industrial				2,653				2,546				107				4.2	%
Large commercial & industrial				2,784				3,646				(862	)			(23.6	)%
Public authorities & electric railroads				1,574				1,497				77				5.1	%
				7,011				7,689				(678	)			(8.8	)%
Delivery only(b)
Small commercial & industrial				5,406				4,327				1,079				24.9	%
Large commercial & industrial				9,117				6,894				2,223				32.2	%
Public authorities & electric railroads				1,264				954				310				32.5	%
				15,787				12,175				3,612				29.7	%
	Total PPO and delivery only			22,798				19,864				2,934				14.8	%
Total retail deliveries				66,193				65,324				869				1.3	%

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(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 AES.

126

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			Nine Months
			Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	1,780			$	1,778			$	2				0.1	%
Small commercial & industrial				1,232				1,289				(57	)			(4.4	)%
Large commercial & industrial				207				240				(33	)			(13.8	)%
Public authorities & electric railroads				224				247				(23	)			(9.3	)%
	Total full service			3,443				3,554				(111	)			(3.1	)%
PPO(b)
Small commercial & industrial				184				174				10				5.7	%
Large commercial & industrial				163				199				(36	)			(18.1	)%
Public authorities & electric railroads				87				81				6				7.4	%
				434				454				(20	)			(4.4	)%
Delivery only(c)
Small commercial & industrial				102				106				(4	)			(3.8	)%
Large commercial & industrial				125				133				(8	)			(6.0	)%
Public authorities & electric railroads				25				25				—				—
				252				264				(12	)			(4.5	)%
Total PPO and delivery only				686				718				(32	)			(4.5	)%
Total electric retail revenues				4,129				4,272				(143	)			(3.3	)%
Wholesale and miscellaneous revenue(d)				329				250				79				31.6	%
Total electric revenue			$	4,458			$	4,522			$	(64	)			(1.4	)%

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(a)		Full service revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.
(b)		Revenue from customers choosing the ComEd PPO includes an energy charge at market rates, transmission and distribution charges and a CTC charge.
(c)		Delivery only revenue from customers choosing an AES includes a distribution charge and a CTC charge. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from AES were included in wholesale and miscellaneous revenue.
(d)		Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

127

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     The changes in electric retail revenues for the nine months ended September 30, 2004, as compared to the same period in 2003, are attributable to the following:

			Increase
			(Decrease)
Customer choice			$	(113	)
Weather				(112	)
Rate changes				(62	)
Volume				144
	Electric retail revenue		$	(143	)
PJM Transmission				106
Other				(27	)
	Wholesale and miscellaneous revenue			79
	Total decrease in electric retail revenue		$	(64	)

      Customer Choice. As noted, all ComEd customers have the choice to purchase energy from an AES. This choice generally does not affect the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd.

      For the nine months ended September 30, 2004, the energy provided by AESs was 15,787 GWhs, or 24%, as compared to 12,175 GWhs, or 19%, for the same period in 2003.

      The decrease in revenues reflects customers in Illinois electing to purchase energy from an AES or the PPO. As of September 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,600 as compared to 20,000 as of September 30, 2003, representing less than 1% of total customers in each period. However, MWhs delivered to such customers increased from approximately 19.9 million for the nine months ended September 30, 2003 to approximately 22.8 million for nine months ended September 30, 2004, or from 30% to 34% of total year-to-date retail deliveries.

      Weather. The weather conditions for the nine months ended September 30, 2004 were unfavorable compared to the same period in 2003. Cooling degree-days decreased 12% for the nine months ended September 30, 2004 compared to the same period in 2003 and were 26% lower than normal. Heating degree-days decreased 8% for the nine months ended September 30, 2004 compared to the same period in 2003, and were 5% lower than normal.

      Rate Changes. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreases the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $131 million for the nine months ended September 30, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates paid by small and large commercial and industrial customers totaling $58 million. For the nine months ended September 30, 2004 and September 30, 2003, ComEd collected approximately $131 million and $262 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, and increases in ComEd’s OATT effective May 1, 2004, ComEd anticipates that this revenue source will decline to approximately $180 million for 2004 and range from $100 million to $180 million annually in 2005 and 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

      Volume. ComEd’s electric revenues increased as a result of higher delivery volume, exclusive of the effect of weather and customer choice, due to an increased number of customers and increased usage per customer, primarily residential and large and small commercial and industrial.

128

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      PJM Transmission. ComEd’s transmission revenues and purchased power expense each increased by $106 million in the nine months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.

	Purchased Power

      The increase in purchased power expense was primarily attributable to an increase of $78 million due to higher volume offset by a $94 million decrease as a result of customers choosing to purchase energy from an AES, a $56 million decrease due to unfavorable weather conditions, and a $14 million decrease due to the mix of average pricing related to ComEd’s PPA with Generation. ComEd’s transmission revenues and purchased power expense each increased by $106 million in the nine months ended September 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.

	Operating and Maintenance

      The changes in operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Charge recorded at ComEd in 2003(a)		$	(41	)
Severance, pension and postretirement benefit costs associated with The Exelon Way			(39	)
Decreased payroll expense due to fewer employees(b)			(19	)
FERC annual fees(c)			(10	)
Incremental storm costs			(8	)
Environmental charges			(6	)
Allowance for uncollectible accounts expense			(6	)
Contractors			(4	)
Injuries and damages claim charges			(4	)
Employee fringe benefits(d)			(1	)
Higher corporate allocations(e)			34
Tax consultant fees(f)			5
Other			(13	)
Decrease in operating and maintenance expense		$	(112	)

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(a)		In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.
(b)		ComEd has fewer employees as a result of The Exelon Way terminations.
(c)		After joining PJM on May 1, 2004, ComEd is no longer charged annual fees by the FERC. PJM pays the annual FERC fees. This represents the reversal of annual FERC fees.
(d)		During the second quarter of 2004, ComEd adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $5 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.
(e)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in ComEd comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.
(f)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 to the Combined Notes to Consolidated Financial Statements for more information).

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	Depreciation and Amortization

		Nine Months
		Ended
		September 30,
										Increase
		2004				2003				(Decrease)
Depreciation expense		$	245			$	229			$	16
Recoverable transition costs amortization			35				34				1
Other amortization expense			29				24				5
Total depreciation and amortization		$	309			$	287			$	22

      The increase in depreciation expense is primarily due to capital additions.

      Recoverable transition costs amortization remained constant in the nine months ended September 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $97 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.

	Taxes Other Than Income

      Taxes other than income decreased for nine months ended September 30, 2004 as compared to the same period in 2003 as a result of $6 million in 2003 for additional use tax payments, a $4 million decrease in payroll taxes as a result of a fewer number of employees and a refund of $8 million for Illinois Electricity Distribution taxes in 2004 partially offset by a refund of $5 million for the Illinois Electricity Distribution taxes in 2003.

	Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities

      The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased as a result of scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates. Effective December 31, 2003, upon the adoption of FIN No. 46-R, ComEd deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). ComEd no longer records distributions on mandatorily redeemable preferred securities, but records interest expense to affiliates related to ComEd’s obligations to the financing trusts. This decrease was offset by $4 million of less allowance for funds used during construction (AFUDC) debt recorded during the nine months ended September 30, 2004 as a result of lower construction work in process balances.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      During the nine months ended September 30, 2004, ComEd has $13 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.

	Net Loss on Extinguishment of Long-Term Debt

      In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt. During the nine months ended September 30, 2004, ComEd recorded a charge of $106 million associated with the retirement of debt under the plan. The components of this charge included the following: $63 million related to prepayment premiums; $11 million related to net unamortized premiums, discounts and debt issuance costs; $23 million of losses on reacquired debt previously deferred as regulatory assets; and $9 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets.

	Other, Net

      The change in Other, net is primarily related to the reversal of a $12 million reserve for potential plant disallowance in 2003 as a result of the Agreement (see “Operating and Maintenance” above), a reduction in

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	Income Taxes

      The effective income tax rate was 41% for the nine months ended September 30, 2004, compared to 40% for the nine months ended September 30, 2003. The increase in the effective tax rate is primarily attributable to adjustments to prior period income taxes in connection with the completion of the 2003 tax return and the adoption of FSP FAS 106-2. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

	Cumulative Effect of a Change in Accounting Principle

      On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million.

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, participation in the intercompany money pool or capital contributions from Exelon. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. 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 Issues” 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

      ComEd’s cash flows from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy, weather and customer choice on its revenues. Cash flows from operations have been and are expected to continue to provide 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 ComEd’s rate regulatory environment, although any effects are not expected to hinder ComEd’s ability to fund its business requirements.

      Cash flows from operations for the nine months ended September 30, 2004 and 2003 were $867 million and $636 million, respectively. Changes in ComEd’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

      In addition to the items mentioned in “Results of Operations,” ComEd’s operating cash flows for the nine months ended September 30, 2004 and 2003 were affected by the following items:

	•	During 2003, ComEd made additional payments to Generation for amounts owed under the PPA. At September 30, 2004 and December 31, 2003, ComEd had accrued payments due to Generation under the PPA of $188 million and $171 million, respectively. At September 30, 2003 and December 31, 2002, ComEd had accrued payments due to Generation under the PPA of $162 million and $339 million, respectively.
	•	ComEd participates in Exelon’s deferred benefit pension plans. Discretionary contributions by ComEd to the plans were $216 million for the nine months ended September 30, 2004 compared to $174 million for the same period in 2003. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits.

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	•	During the third quarter of 2004, ComEd paid $63 million for call premiums on the retirement of debt. See “Cash Flows from Financing Activities” for further information regarding debt retirements pursuant to the accelerated liability management plan.

      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 of September 30, 2004, the majority of the deferred tax liabilities related to the fossil plant sale are reflected in ComEd’s Consolidated Balance Sheets with the remainder having been allocated to the Consolidated Balance Sheets of Generation in connection with Exelon’s 2001 corporate restructuring. The total 1999 income tax liability deferred as a result of these transactions was approximately $1.1 billion. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd’s positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. Any required payments could be significant to the cash flows of ComEd. ComEd’s management believes ComEd’s reserve for interest, which has been established in the event that such positions are not sustained, has been appropriately recorded in accordance with SFAS No. 5. However, the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.

	Cash Flows from Investing Activities

      Cash flows provided by investing activities were $355 million for the nine months ended September 30, 2004 compared to cash flows used in investing activities of $467 million for the same period in 2003. The change in cash flows from investing activities was primarily attributable to $552 million of net proceeds from an investment in and borrowings from the Exelon intercompany money pool, an increase of $223 million in receipts from Unicom Investments, Inc. related to an intercompany note payable and $37 million of net changes in restricted cash. ComEd’s investing activities for the nine months ended September 30, 2004 were funded primarily through operating activities.

      ComEd’s capital expenditures for the nine months ended September 30, 2004 and 2003 were $518 million and $537 million, respectively. ComEd estimates that it will spend up to approximately $690 million in total capital expenditures for 2004. This represents an increase of approximately $75 million more than had been previously planned, primarily as a result of expansion of the ComEd distribution system to support new business and customer growth. Although not anticipated, ComEd believes it could obtain any needed financing through borrowings, the issuance of debt or preferred securities, or capital contributions from Exelon. ComEd’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

	Cash Flows from Financing Activities

      Cash flows used in financing activities for the nine months ended September 30, 2004 were $1,240 million as compared to cash flows used in financing activities of $63 million in 2003. The increase in cash flows used in financing activities is primarily attributable to the net retirement of long-term debt of $1,059 million in 2004, inclusive of the debt retired as part of the liability management plan discussed below, and net proceeds of long-term debt and preferred securities of $288 million in 2003. During the nine months ended September 30, 2003, ComEd also repaid $71 million of commercial paper and paid $45 million to settle interest-rate swaps. During the nine months ended September 30, 2004, ComEd received $26 million from the settlement of interest-rate swaps and $17 million from borrowings from the Exelon intercompany money pool. Additionally, ComEd paid $320 million in dividends to Exelon during the nine months ended September 30, 2004 compared to $305 million in dividends during the same period in 2003.

      From time to time and as market conditions warrant, ComEd may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of ComEd’s balance sheet. In the third quarter of 2004, Exelon initiated an accelerated liability management plan at ComEd that targets the elimination of $1.2 billion of debt from ComEd’s balance sheet by the end of 2004. Through

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	Credit Issues

      Exelon Credit Facility. ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. At December 31, 2003, ComEd, along with Exelon Corporate, PECO and Generation, participated in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and ComEd’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

      Capital Structure. ComEd’s capital structure at September 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

      Intercompany Money Pool. A description of the intercompany money pool, and ComEd’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the nine months ended September 30, 2004, ComEd earned $2.4 million, net in interest on its investments and borrowings in the intercompany money pool.

      Security Ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in the 2003 Form 10-K for a discussion of ComEd’s security ratings.

      Shelf Registration. As of September 30, 2004, ComEd has a current effective shelf registration statement for the sale of $555 million of securities. ComEd’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, ComEd’s current financial condition, its securities ratings and market conditions.

      Fund Transfer Restrictions. At September 30, 2004, ComEd had retained earnings of $1,075 million, of which $1,078 million had been appropriated for future dividend payments. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — ComEd” in the 2003 Form 10-K for information regarding restrictions under Federal and Illinois law and under the agreements governing ComEd Financing II and III regarding dividend payments by ComEd. ComEd is precluded from lending or extending credit or indemnity to Exelon.

	Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

      Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. ComEd’s contractual obligations and commercial commitments as of September 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

	•	See Note 9 and Note 19 to the Combined Notes to Consolidated Financial Statements for discussion of material changes in ComEd’s debt from the amounts set forth in the 2003 Form 10-K.

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PECO ENERGY COMPANY

General

      PECO operates in a single business segment, and its operations consist of the regulated sale of electricity and distribution and transmission services in southeastern Pennsylvania and the sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

Executive Overview

      Financial Results. PECO’s net income decreased 1% for the three months ended September 30, 2004 as compared to the same period in 2003. Operating income, while reflecting various changes in revenues and operating expenses, was unchanged between periods.

      PECO’s net income increased 2% for the nine months ended September 30, 2004 as compared to the same period in 2003 and reflects higher other income. Operating income, while reflecting various changes in revenues and operating expenses, was unchanged between periods.

      The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K for a discussion of PECO’s implementation of The Exelon Way.

      Financing Activities. During the nine months ended September 30, 2004, PECO refinanced $75 million of First and Refunding Mortgage Bonds and made scheduled repayments of $286 million on its long-term debt to PECO Energy Transition Trust. PECO met its capital resource commitments primarily with internally generated cash. When necessary, PECO obtains funds from external sources, including the capital markets, the intercompany money pool, and through bank borrowings.

      Regulatory Developments — Through and Out Proceeding. PECO currently recognizes approximately $4 million of annual revenue from T&O rates for energy flowing across PECO’s transmission system. On March 19, 2004, the FERC issued an order to eliminate these rates effective May 1, 2004, which was subsequently deferred until December 1, 2004. The T&O rates are to be replaced by a new long-term transmission pricing structure that will eliminate seams in the PJM and Midwest ISO regions. Transmission owners in PJM, the Midwest ISO and other parties filed various pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. On October 1, 2004, PECO along with other transmission owners in PJM, participated in the filing of a Regional Pricing Proposal, which if accepted by the FERC, could minimize PECO’s loss of T&O revenues. Depending upon which proposal is accepted by the FERC, or if FERC creates a new alternative, PECO’s results of operation could be negatively affected.

      Rate Design Proceeding. Additionally, certain PJM transmission owners, including PECO, are subject to a rate design proceeding before the FERC. One or more filings will be made in January 2005 to address, among other items, how costs associated with new investments should be recovered. PECO is presently evaluating the extent to which it will participate in this proceeding.

      At this early stage, PECO cannot predict the outcome of either of the above proceedings; however, these proceedings could lead to adverse impacts on the results of operations of PECO.

      Outlook for the Remainder of 2004 and Beyond. PECO’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO — Executive Summary” in the 2003 Form 10-K.

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Results of Operations

	Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

				Three Months
				Ended
				September 30,								Favorable
												(Unfavorable)
				2004				2003				Variance
Operating revenues				$	1,124			$	1,149			$	(25	)
Operating expenses
	Purchased power				458				482				24
	Fuel				35				28				(7	)
	Operating and maintenance				122				192				70
	Depreciation and amortization				144				134				(10	)
	Taxes other than income				64				12				(52	)
		Total operating expenses			823				848				25
Operating income					301				301				—
Other income and deductions
	Interest expense				(76	)			(75	)			(1	)
	Distributions on mandatorily redeemable preferred securities				—				(1	)			1
	Equity in losses of unconsolidated affiliates				(6	)			—				(6	)
	Other, net				3				(10	)			13
		Total other income and deductions			(79	)			(86	)			7
Income before income taxes					222				215				7
Income taxes					83				74				(9	)
Net income					139				141				(2	)
Preferred stock dividends					(1	)			(1	)			—
Net income on common stock				$	138			$	140			$	(2	)

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	Operating Revenue

      PECO’s electric sales statistics were as follows:

			Three Months
			Ended
			September 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				2,906				3,333				(427	)			(12.8	)%
Small commercial & industrial				1,790				1,753				37				2.1	%
Large commercial & industrial				3,949				4,013				(64	)			(1.6	)%
Public authorities & electric railroads				234				217				17				7.8	%
	Total full service			8,879				9,316				(437	)			(4.7	)%
Delivery only(b)
Residential				636				258				378				146.5	%
Small commercial & industrial				444				520				(76	)			(14.6	)%
Large commercial & industrial				229				208				21				10.1	%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			1,309				986				323				32.8	%
Total retail deliveries				10,188				10,302				(114	)			(1.1	)%

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(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 AES.
(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than one GWh per quarter.

			Three Months
			Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	409			$	466			$	(57	)			(12.2	)%
Small commercial & industrial				213				211				2				0.9	%
Large commercial & industrial				290				292				(2	)			(0.7	)%
Public authorities & electric railroads				20				19				1				5.3	%
	Total full service			932				988				(56	)			(5.7	)%
Delivery only(b)
Residential				50				20				30				150.0	%
Small commercial & industrial				24				28				(4	)			(14.3	)%
Large commercial & industrial				6				5				1				20.0	%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			80				53				27				50.9	%
Total electric retail revenues				1,012				1,041				(29	)			(2.8	)%
Wholesale and miscellaneous revenue(d)				52				55				(3	)			(5.5	)%
Total electric revenue			$	1,064			$	1,096			$	(32	)			(2.9	)%

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(a)		Full service revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

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(b)		Delivery only revenue reflects revenue from customers receiving generation from an AES, which includes a distribution charge and a CTC charge.
(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than $1 million per quarter.
(d)		Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

     The changes in electric retail revenues for the three months ended September 30, 2004, as compared to the same period in 2003, were as follows:

		Increase
		(Decrease)
Weather		$	(70	)
Customer choice			(21	)
Rate mix			(7	)
Volume			62
Rate change			7
Decrease in electric retail revenue		$	(29	)

      Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact was unfavorable compared to the prior year. Cooling degree-days decreased 16% and heating degree-days decreased 8%.

      Customer Choice. All PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.

      For the three months ended September 30, 2004, the energy provided by AESs was 1,309 GWhs, or 13%, as compared to 986 GWhs, or 10%, for the three months ended September 30, 2003. As of September 30, 2004, the number of customers served by AESs was 281,600, or 18%, as compared to 120,300 or 8%, as of September 30, 2003. The increases in both energy provided by AESs and the number of customers served by AESs were due to the assignment of residential customers to AESs in December 2003, as required by the PUC and PECO’s final electric restructuring order.

      Rate Mix. The decrease in revenues from rate mix was due to changes in monthly usage patterns in all customer classes.

      Volume. Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily to an increased number of customers and increased usage by all customer classes.

      Rate change. Revenues increased $7 million due to a scheduled phase-out of merger-related rate reductions. In connection with the PUC’s approval of the merger of PECO and Unicom Corporation into Exelon in 2000, PECO entered into a settlement agreement with intervening parties and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005. Consequently, rates were reduced from the levels that otherwise would have been in effect pursuant to the PUC approved restructuring settlement by $60 million annually until January 1, 2004 when the reduction decreased to $40 million annually, which will be in effect through December 31, 2005.

      Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power.

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      PECO’s gas sales statistics for the three months ended September 30, 2004 as compared to the same period in 2003 were as follows:

		Three Months
		Ended
		September 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			3,866				3,498				368				10.5	%
Transportation			6,167				6,012				155				2.6	%
Total			10,033				9,510				523				5.5	%

		Three Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Retail sales			$55				$47				$ 8				17.0	%
Transportation			4				4				—				—
Resales and other			1				2				(1	)			(50.0	)%
Total			$60				$53				$ 7				13.2	%

      The change in gas retail revenue for the three months ended September 30, 2004 as compared to the same period in 2003, was due to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2004. The average rate per mmcf for the three months ended September 30, 2004 was 22% higher than the rate for the same period in 2003. PECO’s gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. PECO anticipates that its purchased gas cost rates will be reduced effective December 1, 2004 in connection with a settlement approved by the PUC in September 2004. This decrease will have no impact on PECO’s operating income.

	Purchased Power

      The decrease in purchased power expense was primarily attributable to $29 million related to lower sales due to unfavorable weather conditions and $21 million from customers in Pennsylvania assigned to or selecting an AES, partially offset by $28 million of increased sales exclusive of the effect of weather conditions.

	Fuel

      The increase in fuel expense was attributable to higher gas costs.

	Operating and Maintenance

      The changes in operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Severance, pension and postretirement benefit costs associated with The Exelon Way		$	(45	)
Decreased incremental storm costs			(15	)
Automated meter reading system implementation costs in 2003			(13	)
Allowance for uncollectible accounts expense			(7	)
Decreased payroll expense due to fewer employees(a)			(3	)
Higher corporate allocations(b)			9
Employee fringe benefits(c)			4
Decrease in operating and maintenance expense		$	(70	)

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(a)		PECO has fewer employees as a result of The Exelon Way.
(b)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in PECO comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.
(c)		During the second quarter of 2004, PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $1 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

	Depreciation and Amortization

		Three Months
		Ended
		September 30,
										Increase
		2004				2003				(Decrease)
Competitive transition charge amortization		$	108			$	96			$	12
Depreciation expense			32				33				(1	)
Other amortization expense			4				5				(1	)
Total depreciation and amortization		$	144			$	134			$	10

      The additional amortization of the CTC is in accordance with PECO’s settlement under the Pennsylvania Competition Act.

	Taxes Other Than Income

      The increase in taxes other than income was primarily attributable to $58 million related to the reversal of real estate tax accruals during 2003.

	Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities

      The aggregate of interest expense and distributions on mandatorily redeemable preferred securities was unchanged and reflected decreased expense due to lower outstanding debt and refinancings at lower rates offset by a reversal in 2003 of accrued interest expense on Federal income taxes of $8 million to reflect actual interest paid. Effective December 31, 2003, with the adoption of FIN No. 46-R, PECO deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.

	Equity in Losses of Unconsolidated Affiliates

      PECO had $6 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.

	Other, Net

      The increase was primarily attributable to a reversal in 2003 of accrued interest on Federal income taxes of $14 million to reflect actual interest received.

	Income Taxes

      The effective tax rate was 37% for the three months ended September 30, 2004 as compared to 35% for the same period in 2003. The increase in the effective tax rate was primarily attributable to adjustments to prior period income taxes in connection with the completion of the 2003 tax return. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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Results of Operations

	Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

				Nine Months
				Ended
				September 30,								Favorable
												(Unfavorable)
				2004				2003				Variance
Operating revenues				$	3,395			$	3,328			$	67
Operating expenses
	Purchased power				1,257				1,290				33
	Fuel				368				285				(83	)
	Operating and maintenance				387				453				66
	Depreciation and amortization				395				370				(25	)
	Taxes other than income				181				123				(58	)
		Total operating expenses			2,588				2,521				(67	)
Operating income					807				807				—
Other income and deductions
	Interest expense				(229	)			(243	)			14
	Distributions on mandatorily redeemable preferred securities				—				(6	)			6
	Equity in losses of unconsolidated affiliates				(19	)			—				(19	)
	Other, net				8				—				8
		Total other income and deductions			(240	)			(249	)			9
Income before income taxes					567				558				9
Income taxes					195				193				(2	)
Net income					372				365				7
Preferred stock dividends					(3	)			(4	)			1
Net income on common stock				$	369			$	361			$	8

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	Operating Revenue

      PECO’s electric sales statistics were as follows:

			Nine Months
			Ended
			September 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				7,922				8,723				(801	)			(9.2	)%
Small commercial & industrial				5,160				5,065				95				1.9	%
Large commercial & industrial				11,270				11,190				80				0.7	%
Public authorities & electric railroads				686				692				(6	)			(0.9	)%
	Total full service			25,038				25,670				(632	)			(2.5	)%
Delivery only(b)
Residential				1,706				708				998				141.0	%
Small commercial & industrial				1,301				1,044				257				24.6	%
Large commercial & industrial				569				610				(41	)			(6.7	)%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			3,576				2,362				1,214				51.4	%
Total retail deliveries				28,614				28,032				582				2.1	%

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(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 AES.
(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than one GWh per quarter.

			Nine Months
			Ended
			September 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	1,021			$	1,122			$	(101	)			(9.0	)%
Small commercial & industrial				587				585				2				0.3	%
Large commercial & industrial				840				825				15				1.8	%
Public authorities & electric railroads				60				62				(2	)			(3.2	)%
	Total full service			2,508				2,594				(86	)			(3.3	)%
Delivery only(b)
Residential				131				52				79				151.9	%
Small commercial & industrial				67				54				13				24.1	%
Large commercial & industrial				15				16				(1	)			(6.3	)%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			213				122				91				74.6	%
Total electric retail revenues				2,721				2,716				5				0.2	%
Wholesale and miscellaneous revenue(d)				151				164				(13	)			(7.9	)%
Total electric revenue			$	2,872			$	2,880			$	(8	)			(0.3	)%

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(a)		Full service revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

141

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(b)		Delivery only revenue reflects revenue from customers receiving generation from an AES, which includes a distribution charge and a CTC charge.
(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than $1 million per quarter.
(d)		Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

     The changes in electric retail revenues for the nine months ended September 30, 2004, as compared to the same period in 2003, were as follows:

		Increase
		(Decrease)
Volume		$	128
Rate change			16
Weather			(62	)
Customer choice			(63	)
Rate mix			(14	)
Increase in electric retail revenue		$	5

      Volume. Exclusive of the effect of weather conditions and customer choice, higher delivery volume related primarily to an increased number of customers and increased usage by all customer classes.

      Rate change. Revenues increased $16 million due to a scheduled phase-out of merger-related rate reductions.

      Weather. The weather impact was unfavorable compared to the prior year. Heating degree-days decreased 8% and cooling degree-days remained relatively unchanged

      Customer Choice. As noted, all PECO customers may choose to purchase energy from an AES. This choice does not affect kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.

      For the nine months ended September 30, 2004, the energy provided by AESs was 3,576 GWhs, or 12%, as compared to 2,362 GWhs, or 8%, for the nine months ended September 30, 2003. As of September 30, 2004, the number of customers served by AESs was 281,600, or 18%, as compared to 120,300, or 8%, as of September 30, 2003. The increases in both the energy provided by AESs and the number of customers served by AESs were due to the assignment of small commercial and industrial customers and residential customers to AESs in May and December 2003, respectively, as required by the PUC and PECO’s final electric restructuring order.

      Rate Mix. The decrease in revenues from rate mix was due to changes in monthly usage patterns in all customer classes during the nine months ended September 30, 2004 as compared to the same period in 2003.

      Electric wholesale and miscellaneous revenue includes PECO’s proportionate share of the transmission revenues generated by PJM’s control of the PJM network transmission assets, including PECO’s. Additionally, PECO pays PJM for its use of these transmission assets, and this expense is recorded in purchased power. Electric wholesale and miscellaneous revenue decreased $13 million due to lower PJM transmission revenue.

      PECO’s gas sales statistics for the nine months ended September 30, 2004 as compared to the same period in 2003 were as follows:

		Nine Months
		Ended
		September 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			41,831				44,183				(2,352	)			(5.3	)%
Transportation			19,709				19,954				(245	)			(1.2	)%
Total			61,540				64,137				(2,597	)			(4.0	)%

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		Nine Months
		September 30,
Revenue		2004				2003				Variance				% Change
Retail sales		$	485			$	418			$	67				16.0	%
Transportation			13				14				(1	)			(7.1	)%
Resales and other			25				16				9				56.3	%
Total		$	523			$	448			$	75				16.7	%

      The changes in gas retail revenue for the nine months ended September 30, 2004 as compared to the same period in 2003, were as follows:

		Increase
		(Decrease)
Rate changes		$	89
Weather			(21	)
Volume			(1	)
Increase in gas retail revenues		$	67

      Rate Changes. The favorable variance in rates was attributable to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003, and March 1, 2004. The average rate per mmcf for the nine months ended September 30, 2004 was 38% higher than the rate for the same period in 2003.

      Weather. The weather conditions were unfavorable compared to the prior year. Heating degree-days decreased 8% compared to the same period in 2003.

      Volume. Exclusive of the effect of weather conditions, revenues were lower in the nine months ended September 30, 2004 compared to the same period in 2003 due primarily to decreased sales in the residential and small commercial and industrial classes.

      Resales and other revenue increased $9 million primarily due to increased off-system sales.

	Purchased Power

      The decrease in purchased power expense was attributable to $63 million from customers in Pennsylvania assigned to or selecting an AES, a $26 million decrease associated with lower sales due to unfavorable weather conditions and a $13 million decrease in PJM transmission expense, partially offset by an increase of $59 million related to increased sales exclusive of weather conditions and $10 million of higher prices.

	Fuel

      The increase in fuel expense was primarily attributable to $89 million of higher gas costs and $13 million related to increased off-system sales, partially offset by a $14 million decrease associated with lower sales due to unfavorable weather conditions.

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	Operating and Maintenance

      The changes in operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Severance, pension and postretirement benefit costs associated with The Exelon Way		$	(35	)
Decreased incremental storm costs			(17	)
Automated meter reading system implementation costs in 2003			(16	)
Decreased payroll expense due to fewer employees(a)			(14	)
Allowance for uncollectible accounts expense			(9	)
Higher corporate allocations(b)			28
Other			(3	)
Decrease in operating and maintenance expense		$	(66	)

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(a)		PECO has fewer employees as a result of The Exelon Way terminations
(b)		Higher corporate allocations primarily result from higher corporate governance allocations and employee fringe benefits. Corporate governance allocations increased as a result of the 2004 sale of certain Enterprises companies resulting in PECO comprising a greater percentage of Exelon and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

	Depreciation and Amortization

		Nine Months
		Ended
		September 30,
										Increase
		2004				2003				(Decrease)
Competitive transition charge amortization		$	282			$	256			$	26
Depreciation expense			96				99				(3	)
Other amortization expense			17				15				2
Total depreciation and amortization		$	395			$	370			$	25

      The additional amortization of the CTC is in accordance with PECO’s settlement under the Pennsylvania Competition Act.

	Taxes Other Than Income

      The increase in taxes other than income was primarily attributable to $58 million related to the reversal of real estate tax accruals during 2003 and $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $5 million of lower capital stock tax.

	Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities

      The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and refinancings at lower rates, partially offset by a reversal in 2003 of accrued interest expense on Federal income taxes of $8 million to reflect actual interest paid. Effective December 31, 2003, with the adoption of FIN No. 46-R, PECO deconsolidated its financing trusts (see Note 2 of the Combined Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.

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	Equity in Losses of Unconsolidated Affiliates

      In 2004, PECO had $19 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.

	Other, Net

      The increase was primarily attributable to a reversal in 2003 of accrued interest on Federal income taxes of $14 million to reflect actual interest received, partially offset by a $5 million decrease in interest income.

	Income Taxes

      The effective tax rate was 34% for the nine months ended September 30, 2004 as compared to 35% for the same period in 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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 a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the “Credit Issues” 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

      PECO’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO’s future cash flows will be affected by its ability to achieve operating cost reductions and the impact of the economy and weather on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow sufficient to meet operating and capital expenditures requirements for the foreseeable future.

      Cash flows from operations for the nine months ended September 30, 2004 and 2003 were $790 million and $757 million, respectively. Changes in PECO’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

      In addition to the items mentioned in “Results of Operations,” PECO’s operating cash flows for the nine months ended September 30, 2004 and 2003 were affected by the following items:

	•	Deferred natural gas costs decreased $52 million during the nine months ended September 30, 2004 resulting in an increase to operating cash flows. During 2003, an increase in deferred natural gas costs of $33 million resulted in a decrease to operating cash flows. PECO’s gas cost rates are subject to periodic adjustments by the PUC that are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates. During 2004, PECO was recovering fuel revenues from customers in excess of gas costs being incurred. During 2003, PECO was incurring gas costs in excess of fuel revenues being recovered from customers.
	•	PECO participates in Exelon’s defined benefit pension plans. Discretionary contributions by PECO to the plans were $8 million during the nine months ended September 30, 2004 compared to $18 million for the same period in 2003. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits.

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	Cash Flows from Investing Activities

      Cash flows used in investing activities for the nine months ended September 30, 2004 and 2003 were $186 million and $61 million, respectively. The $125 million increase in cash used in investing activities was primarily attributable to a change in restricted cash which provided cash flows of $132 million in 2003 and a $26 million investment in the Exelon intercompany money pool in 2004, partially offset by lower construction expenditures of $29 million in 2004. The change in restricted cash is the result of deconsolidating the PECO Energy Transition Trust in December 2003 in accordance with the adoption of FIN No. 46R. PECO’s investing activities during the nine months ended September 30, 2004 were funded by operating activities.

      PECO’s projected capital expenditures for 2004 are $223 million. Approximately 60% of the budgeted 2004 expenditures is for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. PECO anticipates that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO’s proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

	Cash Flows from Financing Activities

      Cash flows used in financing activities for the nine months ended September 30, 2004 were $503 million compared to $677 million for the same period in 2003. The decrease in cash flows used in financing activities was primarily due to a decrease in the retirement of preferred securities of $100 million and an increase in contributions received from Exelon of $89 million, partially offset by an increase in net retirements of long-term debt of $130 million. Additionally, PECO paid dividends of $279 million and $248 million during the nine months ended September 30, 2004 and 2003, respectively, of which $276 million and $244 million, respectively, were common dividends paid to Exelon.

      From time to time and as market conditions warrant, PECO may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of PECO’s balance sheet.

	Credit Issues

      Exelon Credit Facility. PECO mfeets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. At December 31, 2003, PECO participated, along with Exelon Corporate, ComEd and Generation, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and PECO’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

      Capital Structure. PECO’s capital structure at September 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

      Intercompany Money Pool. A description of the intercompany money pool, and PECO’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” During the nine months ended September 30, 2004, PECO earned less than $1 million in interest from its investments in the intercompany money pool.

      Security Ratings. PECO’s access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. On July 22, 2004, Standard & Poor’s Ratings Services lowered its rating on PECO’s First Mortgage Bonds from A to A-. None of PECO’s other securities ratings has changed from those set forth in the 2003 Form 10-K. None of PECO’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.

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      Shelf Registration. As of September 30, 2004, PECO has a current effective shelf registration statement for the sale of $550 million of securities. PECO’s ability to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, PECO’s current financial condition, its securities ratings and market conditions.

      Fund Transfer Restrictions. At September 30, 2004, PECO had retained earnings of $639 million. See “Liquidity and Capital Resources — Credit Issues –Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — PECO” in the 2003 Form 10-K for information regarding fund transfer restrictions.

	Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

      Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. PECO’s contractual obligations and commercial commitments as of September 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

	•	See Note 9 and 19 to the Combined Notes to Consolidated Financial Statements for discussion of material changes in PECO’s debt from the amounts set forth in the 2003 Form 10-K.

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EXELON GENERATION COMPANY, LLC

General

      Generation operates as a single segment and consists of owned and contracted for electric generating facilities, energy marketing operations, a 50% interest in EXRES SHC, Inc., the holding company of Sithe and its subsidiaries and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.

      Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation and has been reflected in Generation’s results of operations from that day forward. Generation’s results of operations have not been adjusted to reflect Exelon Energy Company as a part of Generation for 2003. Exelon Energy Company’s results for the three and nine months ended September 30, 2003 were as follows:

		Three Months				Nine Months
		Ended				Ended
		September 30,				September 30,
		2003				2003
Total revenues		$	146			$	651
Intersegment revenues			—				4
Income (loss) before income taxes			(5	)			(20	)
Income taxes (benefit)			(2	)			(8	)
Net income (loss)			(3	)			(12	)

Executive Overview

      Financial Results. Generation reported net income of $319 million in the three months ended September 30, 2004 as compared to a net loss of $428 million for the same period in 2003, due primarily to the impairment charge of $573 million, net of income taxes, related to the long-lived assets of Boston Generating and a $36 million, net of income taxes, impairment charge related to Generation’s investment in Sithe, both taken in the third quarter of 2003. Generation reported net income of $567 million as compared to a net loss of $339 million for the nine months ended September 30, 2004 as compared to the same period in 2003. This increase was primarily attributable to the impairment charges related to Boston Generating and Sithe in 2003, a gain of $52 million, net of income taxes, recorded on the sale of Boston Generating, partially offset by operating net losses of $28 million, net of income taxes, for Boston Generating incurred during the first five months of 2004, $85 million of net income attributable to the incremental results of AmerGen, Exelon Energy and Sithe and $32 million of net income for the cumulative effect of a change in accounting principle. Generation also experienced improved results due to increased realized margins as a result of its successful forward hedging strategy and increased market prices.

      The Exelon Way. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K for a discussion of Generation’s implementation of The Exelon Way.

      Investment Strategy. On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns the companies that own the Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility. The resulting pre-tax gain of $85 million ($52 million after-tax) was recorded within Exelon’s Consolidated Statements of Income and Comprehensive Income during the second quarter of 2004. On September 1, 2004, Generation completed the transfer of plant operations and power marketing activities of Boston Generating to an entity designated by the lenders.

      On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. Generation’s intent is to fully divest its interest in Sithe, and Generation is actively pursuing opportunities to dispose of Sithe. Generation believes that exercising its call option will provide it with greater certainty of a timely exit from Sithe on favorable terms and conditions.

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      In connection with the consolidation of Sithe on March 31, 2004, Generation recorded assets held for sale related to Sithe’s investments in certain hydroelectric facilities. During the nine months ended September 30, 2004, Sithe completed the sale of certain of its gas, hydroelectric, and the Australian businesses, which represented $160 million and $143 million of assets and liabilities held for sale, respectively, at March 31, 2004, which resulted in a gain on the sale of these businesses of $6 million.

      Financing Activities. On September 30, 2004, Generation had $17 million invested in the Exelon money pool. Also, Generation increased its distributions to Exelon by approximately $64 million during the first nine months of 2004 compared to the same period in the prior year. Generation met its capital resource commitments primarily with internally generated cash. When necessary, Generation obtains funds from external sources, including the capital markets, the intercompany money pool and through bank borrowings.

      Operations. Generation’s nuclear fleet achieved a 94.1% capacity factor during the nine months ended September 30, 2004 compared to 94.5% during the same period in 2003, primarily as a result of an increased number of planned outages in 2004 as compared to 2003. As discussed above, Generation transferred plant operations and power marketing activities of Boston Generating to a special purpose entity designated by the lenders of the Boston Generating credit facility on September 1, 2004.

      Outlook for the Remainder of 2004 and Beyond. Generation’s outlook for the remainder of 2004 is consistent with the discussion within “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation — Executive Summary” in the 2003 Form 10-K.

Results of Operations

	Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

				Three Months
				Ended
				September 30,
												Favorable
				2004				2003				(Unfavorable)
Operating revenues				$	2,253			$	2,537			$	(284	)
Operating expenses
	Purchased power				743				1,240				497
	Fuel				379				449				70
	Impairment of Boston Generating long-lived assets				—				945				945
	Operating and maintenance				432				507				75
	Depreciation and amortization				95				51				(44	)
	Taxes other than income				42				28				(14	)
		Total operating expenses			1,691				3,220				1,529
Operating income (loss)					562				(683	)			1,245
Other income and deductions
	Interest expense				(45	)			(25	)			(20	)
	Equity in earnings (losses) of unconsolidated affiliates				(5	)			53				(58	)
	Other, net				5				(53	)			58
		Total other income and deductions			(45	)			(25	)			(20	)
Income (loss) before income taxes					517				(708	)			1,225
Income taxes					198				(280	)			(478	)
Net income (loss)				$	319			$	(428	)		$	747

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	Operating Revenues

      For the three months ended September 30, 2004 and 2003, Generation’s sales were as follows:

		Three Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates(a)		$	1,218			$	1,339			$	(121	)			(9.0	)%
Wholesale and retail electric sales(b)			759				1,080				(321	)			(29.7	)%
Total electric energy sales revenue			1,977				2,419				(442	)			(18.3	)%
Retail gas sales			55				—				55				n.m.
Trading portfolio			1				1				—				—
Other revenue(c)			220				117				103				88.0%
Total revenue		$	2,253			$	2,537			$	(284	)			(11.2	)%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Includes retail electric sales of Exelon Energy Company in 2004.
(c)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful

		Three Months Ended
		September 30,
Sales (in GWhs)		2004(c)				2003				Variance				% Change
Electric sales to affiliates(a)			30,040				32,237				(2,197	)			(6.8	)%
Wholesale and retail electric sales(b)			21,894				29,613				(7,719	)			(26.1	)%
Total sales			51,934				61,850				(9,916	)			(16.0	)%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Includes retail electric sales of Exelon Energy Company in 2004.
(c)		Sales in 2004 do not include 6,919 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.

     Trading volumes of 7,132 GWhs and 11,086 GWhs for the three months ended September 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

      Generation’s average margin (operating revenue, less purchased power and fuel expenses) and other operating data for the three months ended September 30, 2004 and 2003 are as follows:

			Three Months
			Ended
			September 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates(a)		$	40.55			$	41.54				(2.4	)%
	Wholesale and retail electric sales(b)			34.67				36.47				(4.9	)%
	Total — excluding the trading portfolio			38.07				39.11				(2.7	)%
Average supply cost(c) — excluding the trading portfolio			$	21.60			$	27.31				(20.9	)%
Average margin — excluding the trading portfolio			$	16.47			$	11.80				39.6	%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Includes retail electric sales of Exelon Energy Company in 2004.
(c)		Average supply cost includes purchased power, fuel costs, and PPAs with AmerGen in 2003.

     Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of EITF 03-11 adoption		$	(272	)
Boston Generating			(213	)
Exelon Energy Company and AmerGen operations			143
Other			21
Decrease in wholesale and retail electric sales		$	(321	)

      As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 decreased wholesale and retail sales, which was partially offset by the increase from the acquisition of the remaining 50% of AmerGen in 2003 and the transfer of Exelon Energy to Generation as of January 1, 2004.

      The increase in other wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market as a result of forward hedging and fuel prices, and higher average market prices driven by coal prices in the Midwest and higher oil and gas prices in the Mid-Atlantic region contributed to higher revenues.

      Electric Sales to Affiliates. The decrease in revenue from sales to affiliates included $69 million in lower sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to customers purchasing energy from alternative electric suppliers and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.

      Additionally, due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the three months ended September 30, 2003 was $51 million.

      Retail Gas Sales. Retail gas sales increased $55 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

      Other. Certain other revenues increased for the three months ended September 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004 and higher fuel sales.

	Purchased Power and Fuel

      Generation’s supply source is summarized below:

		Three Months
		Ended
		September 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			35,303				30,152				5,151				17.1	%
Purchases — non-trading portfolio(b)			13,563				24,062				(10,499	)			(43.6	)%
Fossil and hydroelectric generation(c)			3,068				7,636				(4,568	)			(59.8	)%
Total supply			51,934				61,850				(9,916	)			(16.0	)%

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(a)		Excludes AmerGen for 2003. AmerGen generated 5,151 GWhs during the three months ended September 30, 2004.

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(b)		6,919 GWhs of purchased power were netted with sales in 2004 as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 3,725 GWhs in 2003.
(c)		Generation associated with the Boston Generating units represented 3,750 GWhs during the three months ended September 30, 2003.

     The changes in Generation’s purchased power and fuel expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11		$	(272	)
Boston Generating			(178	)
Mark-to-market adjustments on hedging activity			(78	)
Midwest Generation			(62	)
AmerGen and Exelon Energy Company			(59	)
Sithe			52
Volume			17
Price			42
Other			(29	)
Decrease in purchased power and fuel expense		$	(567	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $272 million.

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due to the sale of the business in May 2004.

      Hedging Activity. Mark-to-market gains on hedging activities were $57 million for the three months ended September 30, 2004 compared to losses of $21 million for the same period of 2003.

      Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation.

      AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, and the transfer of Exelon Energy to Generation in 2004, purchased power decreased $124 million, net of fuel expense, which had a significant impact on Generation’s average supply cost decrease for the same period. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, and the purchase of AmerGen, fuel expense increased $65 million as fuel purchases made by Exelon Energy Company and AmerGen’s nuclear fuel amortization did not previously affect Generation’s purchased power and fuel expense.

      Sithe. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.

      Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions. The increase in purchased power was partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

      Price. The increase reflects higher market energy prices due to higher natural gas, oil and coal prices.

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      Other. Other decreases in purchased power and fuel expense were primarily due to $20 million of lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM during the second quarter of 2004.

	Impairment of the Long Lived Assets of Boston Generating

      In connection with the decision to transition out of the ownership of Boston Generating and the projects during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

	Operating and Maintenance

      The changes in operating and maintenance expense for the three months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Pension, payroll and benefit costs, primarily associated with The Exelon Way		$	(51	)
DOE settlement(a)			(52	)
Boston Generating			(21	)
AmerGen and Exelon Energy Company			80
Sithe			18
Other			(49	)
Decrease in operating and maintenance expense		$	(75	)

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(a)		See Note 15 of the Combined Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement reached with the DOE.

     The decrease in operating and maintenance expense was primarily due to reductions in payroll-related costs associated with the implementation of the programs associated with The Exelon Way, the offset to operating and maintenance expense resulting from the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel, the sale of Boston Generating in May 2004, and a $36 million reduction in the contractual obligation Generation has to ComEd related to decommissioning obligations. Generation is required to refund ComEd the amount of decommissioning trust fund assets in excess of the ARO, if any, at the completion of the decommissioning of the former ComEd nuclear units. In the third quarter of 2004, Generation updated the ARO for the former ComEd plants and was required to impair an asset established during this process (see Depreciation and Amortization discussion below). The obligation to ComEd was reduced as a result of this impairment charge and as such, operating expense was reduced by an equal amount. These decreases in operating and maintenance expense were partially offset by the inclusion of AmerGen, Exelon Energy Company and Sithe’s operating results in Generation’s consolidated results for 2004.

      Nuclear fleet operating data and purchased power costs data for the three months ended September 30, 2004 and 2003 were as follows:

		Three Months
		Ended
		September 30,
		2004				2003
Nuclear fleet capacity factor(a)			95.8	%			95.3	%
Nuclear fleet production cost per MWh(a)		$	10.92			$	11.69
Average purchased power cost for wholesale operations per MWh(b)		$	54.78			$	51.53

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(a)		Includes AmerGen and excludes Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G).
(b)		Includes PPAs with AmerGen in 2003.

     Higher nuclear capacity factors were primarily due to four fewer planned refueling outage days. The four fewer outage days resulted in a $12 million decrease in planned outage costs for the three months ended September 30, 2004 as compared to the same period in 2003. There was one planned outage during the three months ended September 30, 2004, compared to two planned outages during the same period in 2003. The three months ended September 30, 2004 included four unplanned outages, compared to nine unplanned outages during the same period in 2003.

      Lower nuclear production costs were primarily due to the spent fuel storage cost settlement agreement with the DOE which resulted in the reimbursement of $40 million in spent fuel storage costs incurred as operating and maintenance expenses prior to September 30, 2003, and the recording of $12 million of spent fuel storage operating and maintenance expenses incurred from October 1, 2003 to September 30, 2004 within accounts receivable, other.

      In the three months ended September 30, 2004 as compared to the three months ended September 30, 2003, the Quad Cities units operated at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.

	Depreciation and Amortization

      The increase in depreciation and amortization expense for the three months ended September 30, 2004 as compared to the same period in 2003 was primarily due to the establishment of the ARC asset for retired nuclear units of $36 million associated with the third quarter 2004 update of the nuclear decommissioning ARO. This ARC was immediately impaired through depreciation expense as this asset was associated with retired nuclear units that do not have any remaining useful life. The remaining increase is due to capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

	Interest Expense

      The increase in interest expense was primarily related to the additional interest expense incurred from the consolidation of Sithe, the purchase of British Energy’s interest in AmerGen, and the issuance of $500 million of Senior Notes in December 2003. This increase is partially offset by the reduction in expense related to the sale of Boston Generating, and its associated construction loan.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $47 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003 and the consolidation of Sithe in 2004. Equity in earnings of unconsolidated affiliates in 2004 represents equity earnings from Sithe’s 49.5% investment in TEG. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen.

	Other, Net

      The increase in other income for the three months ended September 30, 2004 as compared to the same period in the prior year was primarily due to the $55 million impairment charge for Generation’s investment in Sithe recorded during the third quarter of 2003.

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	Effective Income Tax Rate

      The effective income tax rate was 38% for the three months ended September 30, 2004 compared to 40% for the same period in 2003. This decrease was primarily attributable to the impairment charges recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Results of Operations

	Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

				Nine Months
				Ended
				September 30,
												Favorable
				2004				2003				(Unfavorable)
Operating revenues				$	6,153			$	6,301			$	(148	)
Operating expenses
	Purchased power				1,825				2,881				1,056
	Fuel				1,427				1,156				(271	)
	Impairment of Boston Generating				—				945				945
	Operating and maintenance				1,645				1,397				(248	)
	Depreciation and amortization				218				142				(76	)
	Taxes other than income				137				115				(22	)
		Total operating expenses			5,252				6,636				1,384
Operating income					901				(335	)			1,236
Other income and deductions
	Interest expense				(123	)			(63	)			(60	)
	Equity in earnings (losses) of unconsolidated affiliates				(7	)			90				(97	)
	Other, net				129				(238	)			367
		Total other income and deductions			(1	)			(211	)			210
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles					900				(546	)			1,446
Income taxes					343				(209	)			(552	)
Income (loss) before minority interest and cumulative effect of changes in accounting principles					557				(337	)			894
Minority interest					10				(2	)			12
Income (loss) before cumulative effect of changes in accounting principles					567				(339	)			906
Cumulative effect of changes in accounting principles					32				108				(76	)
Net income (loss)				$	599			$	(231	)		$	830

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	Operating Revenues

      For the nine months ended September 30, 2004 and 2003, Generation’s sales were as follows:

		Nine Months
		Ended
		September 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates(a)		$	2,924			$	3,185			$	(261	)			(8.2	)%
Wholesale and retail electric sales(b)			2,501				2,725				(224	)			(8.2	)%
Total electric energy sales revenue			5,425				5,910				(485	)			(8.2	)%
Retail gas sales			315				—				315				n.m.
Trading portfolio			(2	)			(1	)			(1	)			100.0	%
Other revenue(c)			415				392				23				5.9	%
Total revenue		$	6,153			$	6,301			$	(148	)			(2.3	)%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Includes retail electric sales of Exelon Energy Company in 2004.
(c)		Includes sales related to tolling agreements, including Sithe in 2004, and fossil fuel sales.

n.m. — not meaningful

		Nine Months
		Ended
		September 30,
Sales (in GWhs)		2004				2003				Variance				% Change
Electric sales to affiliates(a)			83,637				89,700				(6,063	)			(6.8	)%
Wholesale and retail electric sales(b)			70,853				80,877				(10,024	)			(12.4	)%
Total sales			154,490				170,577				(16,087	)			(9.4	)%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Sales in 2004 do not include 18,557 GWhs which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes retail electric sales of Exelon Energy Company in 2004.

     Trading volumes of 17,569 GWhs and 28,532 GWhs for the nine months ended September 30, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced proprietary trading activity.

      Generation’s average margin (operating revenue, less purchased power and fuel expense) and other operating data for the nine months ended September 30, 2004 and 2003 are as follows:

			Nine Months
			Ended
			September 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates(a)		$	34.96			$	35.51				(1.5	)%
	Wholesale and retail electric sales(b)			35.30				33.69				4.8	%
	Total — excluding the trading portfolio			35.12				34.65				1.4	%
Average supply cost(c) — excluding the trading portfolio			$	21.05			$	23.67				(11.1	)%
Average margin — excluding the trading portfolio			$	14.07			$	10.98				28.1	%

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(a)		Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.
(b)		Includes retail electric sales of Exelon Energy Company in 2004.
(c)		Average supply cost includes purchased power, fuel costs, and PPAs with AmerGen in 2003.

     Wholesale and Retail Electric Sales. The changes in Generation’s wholesale and retail electric sales for the nine months ended September 30, 2004 compared to the same period in 2003, consisted of the following:

		Increase
		(Decrease)
Effects of EITF 03-11 adoption(a)		$	(715	)
Boston Generating			(159	)
Exelon Energy Company and AmerGen operations			325
Other			325
Decrease in wholesale and retail electric sales		$	(224	)

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(a)		Does not include $9 million of EITF 03-11 adjustments related to fuel sales that are included in other revenues.

     As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchase power and fuel expense in 2004. The sale of Boston Generating in May 2004 decreased wholesale and retail sales, which was partially offset by the increase from the acquisition of the remaining 50% of AmerGen in 2003 and the transfer of Exelon Energy to Generation as of January 1, 2004.

      The increase in other wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market as a result of forward hedging and fuel prices. Higher average market prices in the Midwest region were primarily driven higher by higher coal prices, while the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

      Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of Exelon Energy Company’s assets and operations being transferred to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the nine months ended September 30, 2003 was $159 million.

      The decrease in revenue from sales to affiliates included $108 million in lower sales to Energy Delivery. The lower sales to Energy Delivery were primarily due to customers purchasing energy from an AES and unfavorable weather conditions in the ComEd and PECO service territories compared to the prior year.

      Retail Gas Sales. Retail gas sales increased $315 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

      Other. Certain other revenues increased for the nine months ended September 30, 2004 as compared to the same period in 2003, primarily due to the consolidation of Sithe’s results of operations beginning April 1, 2004.

	Purchased Power and Fuel

      Generation’s supply source is summarized below:

		Nine Months
		Ended
		September 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			102,968				89,101				13,867				15.6	%
Purchases — non-trading portfolio(b)			37,158				63,435				(26,277	)			(41.4	)%
Fossil and hydroelectric generation			14,364				18,041				(3,677	)			(20.4	)%
Total supply			154,490				170,577				(16,087	)			(9.4	)%

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(a)		Excludes AmerGen for 2003. AmerGen generated 14,912 GWhs during the nine months ended September 30, 2004.
(b)		18,557 GWhs were netted with purchased power GWhs in 2004 as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 9,944 GWhs in 2003.

     The changes in Generation’s purchased power and fuel expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
Effects of the adoption of EITF 03-11		$	(724	)
Midwest Generation			(110	)
Boston Generating			(103	)
Mark-to-market adjustments on hedging activity			(57	)
Price			(31	)
Volume			181
Sithe			113
AmerGen and Exelon Energy Company			43
Other			(97	)
Decrease in purchased power and fuel expense		$	(785	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $724 million.

      Midwest Generation. The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the disposition of Boston Generating in May 2004.

      Hedging Activity. Mark-to-market gains on hedging activities were $39 million for the nine months ended September 30, 2004 compared to losses of $18 million for the same period in 2003.

      Price. The decrease primarily reflects lower average fossil fuel costs of $31 million during the nine months ended September 30, 2004 as compared to the same period in 2003. Natural gas, oil and coal prices all decreased during this period.

      Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.

      Sithe. Under the provisions of FIN No. 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of Sithe.

      AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $284 million, net of fuel expense, which had a significant impact on Generation’s average supply cost decrease for the same period. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $326 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s purchased power and fuel expense.

      Other. Other decreases in purchased power and fuel were primarily due to $66 million in lower transmission expense resulting from reduced inter-region transmission as a result of ComEd’s integration into PJM in the second quarter of 2004, and $16 million of additional nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

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	Impairment of the Long-Lived Assets of Boston Generating

      In connection with the decision to transition out of the ownership of Boston Generating and the projects during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

	Operating and Maintenance

      The changes in operating and maintenance expense for the nine months ended September 30, 2004 compared to the same period in 2003 consisted of the following:

		Increase
		(Decrease)
AmerGen and Exelon Energy Company(a)		$	277
Sithe			40
Refueling outage costs			28
Boston Generating			14
Pension, payroll and benefit costs associated with The Exelon Way			(68	)
DOE Settlement(b)			(52	)
Other			9
Increase in operating and maintenance expense		$	248

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(a)		Includes refueling outage expense of $24 million at AmerGen.
(b)		See Note 15 of the Combined Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement reached with the DOE.

     The increase in operating and maintenance expense was primarily due to the inclusion of AmerGen, Exelon Energy Company, and Sithe’s operating results in Generation’s consolidated results for 2004. This increase was partially offset with reductions in payroll-related costs due to implementation of the programs associated with The Exelon Way, and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.

      Nuclear fleet operating data and purchased power costs data for the nine months ended September 30, 2004 and 2003 were as follows:

		Nine Months
		Ended
		September 30,
		2004				2003
Nuclear fleet capacity factor(a)			94.1	%			94.5	%
Nuclear fleet production cost per MWh(a)		$	11.99			$	12.16
Average purchased power cost for wholesale operations per MWh(b)		$	49.11			$	45.42

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(a)		Includes AmerGen and excludes Salem, which is operated by PSE&G.
(b)		Includes PPAs with AmerGen in 2003.

     Lower nuclear capacity factors were primarily due to 51 additional planned refueling outage days, resulting in a $34 million increase in planned outage costs in the nine months ended September 30, 2004 as compared to the same period in 2003. There were six planned outages during the nine months ended September 30, 2004, compared to five planned outages during the same period in 2003. The nine months ended September 30, 2004 included 16 unplanned outages compared to 20 unplanned outages during the same period in 2003. Nuclear capacity factors were also affected by Quad Cities operating at lower than anticipated capacity levels.

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      The lower nuclear production cost is primarily due to the spent fuel storage cost settlement agreement with the DOE which resulted in the reimbursement of $40 million in spent fuel storage costs incurred as operating and maintenance expenses prior to September 30, 2003, and the recording of $12 million of spent fuel storage operating and maintenance expenses incurred from October 1, 2003 to September 30, 2004 within accounts receivable, other.

      The Quad Cities units have intermittently been operating at pre-EPU generation levels due to performance issues with their steam dryers. Generation plans additional expenditures to ensure safe and reliable operations at the EPU output levels by mid-2005.

	Depreciation and Amortization

      The increase in depreciation and amortization expense for the nine months ended September 30, 2004 as compared to the same period in 2003 was primarily due to the establishment of the ARC asset for retired nuclear units of $36 million associated with the third quarter 2004 update of the nuclear decommissioning ARO. This ARC was immediately impaired through depreciation expense as this asset was associated with retired nuclear units that do not have any remaining useful life. The remaining increase is due to capital additions and the consolidation of Sithe, AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

	Interest Expense

      The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December 2003 and additional interest expense incurred as a result of the consolidation of Sithe. This increase is partially offset by the reduction in expense related to the sale of Boston Generating, and its associated construction loan.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      The decrease in equity in earnings of unconsolidated affiliates was primarily due to an $84 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003 and the consolidation of Sithe in 2004. Equity in earnings of unconsolidated affiliates in 2004 represents Sithe’s equity earnings related to its 49.5% investment in TEG and the equity earnings of Sithe prior to the consolidation. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s purchase of British Energy’s 50% interest in AmerGen.

	Other, Net

      The increase in other income for the nine months ended September 30, 2004 as compared to the same period in the prior year was primarily due to the $85 million gain ($52 million, net of taxes) on the disposal of Boston Generating recorded in 2004, versus a $255 million impairment charge related to the Generation’s investment in Sithe Energies recorded in 2003.

	Effective Income Tax Rate

      The effective income tax rate was 38% for the nine months ended September 30, 2004 and 2003. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the effective income tax rate.

	Cumulative Effect of Changes in Accounting Principles

      Net income for the nine months ended September 30, 2004 reflects income of $32 million, net of income taxes, related to the consolidation of Sithe pursuant to FIN No. 46-R which resulted from the reversal of certain guarantees on behalf of Sithe that had been recorded at Generation prior to December 31, 2003, while

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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 a revolving credit facility. See the “Credit Issues” 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

      Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation’s affiliated companies. Generation’s future cash flows from operating activities will be affected by future demand and market prices for energy and its ability to continue to produce and supply power at competitive costs. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flows, sufficient to meet operating and capital expenditures requirements for the foreseeable future.

      Cash flows from operations for the nine months ended September 30, 2004 and 2003 were $1,508 million and $1,141 million, respectively. Changes in Generation’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business and non-cash charges.

      In addition to the items mentioned in “Results of Operations,” Generation’s operating cash flows for the nine months ended September 30, 2004 and 2003 were affected by the following items:

	•	Receivables from Exelon Delivery under the PPA increased $57 million for the nine months ended September 30, 2004, compared to a decrease of $178 million during the same period in 2003.
	•	Net cash received for collateral for power marketing activities for the nine months ended September 30, 2004 was $59 million, compared to $51 million paid during the same period in 2003.
	•	At September 30, 2004, Generation was in a net income tax receivable position compared to a net income tax payable position at September 30, 2003. Comparability of the cash flows for the two periods is affected significantly by this change in the income tax position. The primary driver of the increase in cash from the changes in receivables during the nine months ended September 30, 2004 was the income tax provision of approximately $185 million and the receipt of a $160 million income tax refund during the third quarter of 2004, partially offset by the payment of approximately $64 million for income taxes.
	•	Generation participates in Exelon’s defined benefit pension plans. Discretionary contributions to the plans were $171 million for the nine months ended September 30, 2004 compared to $147 million for the same period in 2003. Generation also contributed $8 million to the pension plan to satisfy ERISA minimum funding requirements. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding pension and postretirement benefits.

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	Cash Flows from Investing Activities

      Cash flows used in investing activities were $732 million and $797 million for the nine months ended September 30, 2004 and 2003, respectively. Generation’s capital expenditures for the nine months ended September 30, 2004 and 2003 were $608 million and $641 million, respectively. Generation’s capital expenditures represent additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Capital expenditures for the nine months ended September 30, 2004 and 2003 are stated net of the settlement of litigation with the DOE of $20 million and net of proceeds from liquidated damages of $92 million, respectively. Generation estimates that it will spend approximately $941 million in total capital expenditures in 2004. Generation anticipates that nuclear refueling outages will increase from eight in 2003 to nine in 2004. Generation’s capital expenditures are expected to be funded by internally generated funds.

      Cash flows from other investing activities in 2004 were primarily attributable to the following:

	•	Proceeds from the sale of three gas turbines of $42 million.
	•	Collection of a $20 million note receivable related to the sale of certain businesses of Sithe during the fourth quarter of 2003 and the first quarter of 2004.
	•	During the second and third quarters of 2004, Sithe received $24 million of cash proceeds from the disposition of businesses previously classified as held for sale.

	Cash Flows from Financing Activities

      Cash flows used in financing activities were $664 million and $299 million for the nine months ended September 30, 2004 and 2003, respectively. The increase in cash flows used in financing activities was primarily a result of a net repayment of intercompany borrowings of $445 million during the nine months ended September 30, 2004, compared to a $178 million net repayment of intercompany borrowings during the same period in 2003, a $54 million increase in distributions to Exelon during the nine months ended September 30, 2004 as compared to the same period in 2003, an increase in the repayment of long term debt of $25 million during the nine months ended September 30, 2004 as compared to the same period in 2003, and the partial repayment of the acquisition note payable to Sithe of $27 million during the nine months ended September 30, 2004.

      From time to time and as market conditions warrant, Generation may engage in long-term debt repurchases via tender offers, open market acquisitions or other viable options to preserve the integrity of Generation’s balance sheet.

	Credit Issues

      Exelon Credit Facility. Generation meets its short-term liquidity requirements primarily through the issuance of commercial paper and intercompany borrowings from Exelon’s intercompany money pool. At December 31, 2003, Generation participated, along with Exelon Corporate, ComEd and PECO, in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement with a group of banks. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion five-year facility and the $750 million three-year facility was reduced to $500 million. These credit agreements, and Generation’s participation therein, are described above under “Credit Issues — Exelon Credit Facility” in “Exelon Corporation — Liquidity and Capital Resources.”

      Capital Structure. Generation’s capital structure at September 30, 2004 is described above under “Credit Issues — Capital Structure” in “Exelon Corporation — Liquidity and Capital Resources.”

      Intercompany Money Pool. A description of the intercompany money pool, and Generation’s participation therein, is set forth above under “Credit Issues — Intercompany Money Pool” in “Exelon Corporation — Liquidity and Capital Resources.” For the nine months ended September 30, 2004, Generation paid $2 million in interest to the money pool.

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      Sithe Long-Term Debt. A description of the Sithe long-term debt consolidated as a result of the adoption of FIN No. 46-R is set forth above under “Credit Issues — Sithe Long-Term Debt” in “Exelon Corporation — Liquidity and Capital Resources.”

      Security Ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in the 2003 Form 10-K for a discussion of Generation’s security ratings.

      Fund Transfer Restrictions. At September 30, 2004, Generation had undistributed earnings of $1,031 million. See “Liquidity and Capital Resources — Credit Issues — Fund Transfer Restrictions” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Generation” in the 2003 Form 10-K for information regarding fund transfer restrictions.

	Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

      Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Generation’s contractual obligations and commercial commitments as of September 30, 2004 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2003 Form 10-K except for the following:

	•	In connection with the transfer of Exelon Energy Company to Generation effective January 1, 2004, Generation acquired $162 million in energy marketing contract guarantees.
	•	Generation acquired a $50 million letter of credit to support the contractual obligations of Sithe and its subsidiaries and issued a $45 million of letter of credit for Power Team to cover collateral calls that had previously been met with cash collateral.
	•	On September 29, 2004, Generation exercised its call option to acquire Reservoir’s 50% interest in Sithe for $97 million. The closing of the call is subject to state and Federal regulatory approvals.

Item 3.	Quantitative and Qualitative Disclosure About Market Risk

      Exelon is exposed to market risks associated with commodity prices, credit, interest rates and equity prices. The inherent risk in market-sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Exelon’s Risk Management Committee (RMC) sets forth risk management policy and objectives and establishes procedures 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 from each of the business units. The RMC reports to the Exelon Board of Directors on the scope of Exelon’s derivative and risk management activities.

Commodity Price Risk

	Generation

      Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity, energy and fossil fuels, including oil, gas, coal, and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and Federal regulatory policies and other events.

	Normal Operations and Hedging Activities

      Electricity available from Generation’s owned or contracted generation supply in excess of its obligations to customers, including Energy Delivery’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,

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	Proprietary Trading Activities

      Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of its 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. The results of the trading portfolio for the nine months ended September 30, 2004 was a loss of $1 million (before taxes) which included a $1 million unrealized mark-to-market loss. The daily Value-at-Risk (VaR) on proprietary trading activity averaged $200,000 of exposure over the last 18 months. Because of the diminutive nature of the proprietary trading portfolio in comparison to Generation’s total gross margin of $2,901 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and VaR limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities.

      Generation’s energy contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 2003 Form 10-K. Those that do not 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 Other Comprehensive Income (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 hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in current earnings.

      The following detailed presentation of the trading and marketing activities of 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, 2004 to September 30, 2004. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging

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(In millions)
Total mark-to-market energy contract net assets (liabilities) at January 1, 2004		$	(216	)
Total change in fair value during 2004 of contracts recorded in earnings			210
Reclassification to realized at settlement of contracts recorded in earnings			(193	)
Reclassification to realized at settlement from OCI			367
Effective portion of changes in fair value — recorded in OCI			(536	)
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market			147
Total mark-to-market energy contract net assets (liabilities) at September 30, 2004		$	(221	)

      The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2004 and December 31, 2003:

			September 30,				December 31,
(In millions)			2004				2003
Current assets			$	403			$	322
Noncurrent assets				422				100
	Total mark-to-market energy contract assets			825				422
Current liabilities(a)				(655	)			(505	)
Noncurrent liabilities				(391	)			(133	)
	Total mark-to-market energy contract liabilities			(1,046	)			(638	)
Total mark-to-market energy contract net assets (liabilities)			$	(221	)		$	(216	)

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(a)		Mark-to-market energy contract liabilities at December 31, 2003 do not reflect a $76 million interest-rate swap which was included in current mark-to-market derivative liabilities within Generation’s Consolidated Balance Sheet.

     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 midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available vary by commodity, region and product. The remainder of the assets 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, 2004 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 it holds or 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.

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      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, the table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when the mark-to-market amounts will settle and either generate or require cash.

				Maturities within
																				2008 and				Total Fair
				2004				2005				2006				2007				Beyond				Value
(In millions)
Normal operations, qualifying cash-flow hedge contracts(a):
	Actively quoted prices			$	3			$	6			$	—			$	—			$	—			$	9
	Prices provided by other external sources				(83	)			(242	)			(32	)			(8	)			—				(365	)
		Total		$	(80	)		$	(236	)		$	(32	)		$	(8	)		$	—			$	(356	)
Normal operations, other derivative contracts(b):
	Actively quoted prices			$	19			$	35			$	(2	)		$	—			$	—			$	52
	Prices provided by other external sources				(14	)			15				5				—				—				6
	Prices based on model or other valuation methods				5				(21	)			14				11				68				77
		Total		$	10			$	29			$	17			$	11			$	68			$	135

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(a)		Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income.
(b)		Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

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     The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of September 30, 2004. 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 other comprehensive income related to cash-flow hedges for the nine months ended September 30, 2004, 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 Other Comprehensive
		Income Activity, Net of Income Tax
		Normal				Interest Rate				Total
		Operations and				and Other				Cash Flow
(In millions)		Hedging Activities				Hedges(a)				Hedges
Accumulated OCI derivative loss at January 1, 2004		$	(133	)		$	(13	)		$	(146	)
Changes in fair value			(311	)			—				(311	)
Reclassifications from OCI to net income			226				12				238
Exelon Energy Company opening balance			2				—				2
Sithe			—				(7	)			(7	)
Accumulated OCI derivative loss at September 30, 2004		$	(216	)		$	(8	)		$	(224	)

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(a)		Includes interest rate hedges at Generation.

Credit Risk

	Generation

      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. 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 reduces 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.

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      The following tables provide information on Generation’s wholesale credit exposure, net of collateral, as of September 30, 2004. The tables 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 Generation’s credit risk by credit rating of its counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through Independent System Operators, which are discussed below.

			Total												Number Of				Net Exposure Of
			Exposure												Counterparties				Counterparties
Rating(a) (In millions, except for			Before Credit				Credit				Net				Greater than 10%				Greater than 10%
counterparties)			Collateral				Collateral				Exposure				of Net Exposure				of Net Exposure
Investment grade			$	199			$	28			$	171				2			$	72
Non-investment grade				73				2				71				1				48
No external ratings
	Internally rated — investment grade			12				—				12				—				—
	Internally rated — non- investment grade			3				—				3				—				—
Total			$	287			$	30			$	257				3			$	120

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(a)		Table does not include credit risk associated with Generation’s retail operations.

			Maturity of Credit Risk Exposure
											Exposure				Total Exposure
			Less than								Greater than				Before Credit
Rating(a) (In millions)			2 Years				2-5 Years				5 Years				Collateral
Investment grade			$	192			$	6			$	1			$	199
Non-investment grade				68				5				—				73
No external ratings
	Internally rated — investment grade			12				—				—				12
	Internally rated — non-investment grade			3				—				—				3
Total			$	275			$	11			$	1			$	287

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(a)		Table does not include credit risk associated with Generation’s retail operations.

     Dynegy. Generation is counterparty to Dynegy, Inc. (Dynegy) in various energy transactions. The credit ratings of Dynegy are below investment grade. As of September 30, 2004, Generation has credit risk associated with Dynegy through Generation’s investment in Sithe. Sithe is a 100% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of March 31, 2004, Generation consolidated the assets and liabilities of Sithe in accordance with the provisions of FIN No. 46-R. As a result, Generation has recorded an asset of $127 million on its Consolidated Balance Sheets related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the terms of SFAS No. 133, “Accounting for Derivatives and Hedging Activities.” If Dynegy were unable to fulfill the terms of the financial swap agreement, Generation would be required to impair the related asset. Exelon estimates, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of its net income of approximately $23 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding Generation’s exercise of a call option to acquire the remaining 50% of Sithe.

      In addition to the asset impairment, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur an impairment of the intangible asset associated with the Independence plant tolling agreement. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of up to $50 million. In the event of a sale of Generation’s investment in Sithe to a third party,

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      Generation had previously disclosed that the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company (Illinois Power), a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On September 30, 2004, Dynegy sold Illinois Power to a third party, which has reduced Generation’s credit risk associated with Dynegy.

      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 express contractual 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 Generation’s 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.

      ISOs. Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, ISO New England, New York ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which is administered by 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, each 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.

Interest Rate Risk

	Exelon

      As of September 30, 2004, a hypothetical 10% increase in the interest rates associated with variable-rate debt would not have a material impact on Exelon’s pre-tax earnings.

      In September 2004, Exelon entered into forward-starting interest-rate swaps in the aggregate amount of $160 million to lock in interest rate levels in anticipation of a future financing. The debt issuance that swaps are hedging was considered probable as of September 30, 2004; therefore, Exelon accounted for the swaps as cash-flow hedges. At September 30, 2004, the swaps had an aggregate fair market value of less than $1 million based on the present value difference between the contract and market rates at September 30, 2004. If these derivative instruments had been terminated at September 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to Exelon.

      The aggregate fair value of these interest-rate swaps that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2004 is estimated to be $6 million in the counterparties’ favor. If the derivative instruments had been terminated at September 30, 2004, this estimated fair value represents the amount Exelon would pay the counterparties.

      The aggregate fair value of these interest-rate swaps that would have resulted from a hypothetical 50 basis point increase in the spot yield at September 30, 2004 is estimated to be $7 million in Exelon’s favor. If the derivative instrument had been terminated at September 30, 2004, this estimated fair value represents the amount the counterparties would pay Exelon.

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	ComEd

      As of September 30, 2004, a hypothetical 10% increase in the interest rates associated with variable-rate debt would not have a material impact on ComEd’s pre-tax earnings.

      ComEd uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Interest-rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd also utilizes forward-starting interest-rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to achieve a lower cost of capital. At September 30, 2004, ComEd did not have any interest-rate swaps designated as cash-flow hedges.

      In 2004, ComEd entered into fixed-to-floating interest-rate swaps in order to maintain its targeted percentage of variable-rate debt associated with fixed-rate debt issuances in the aggregate amount of $240 million. At September 30, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $9 million based on the present value difference between the contract and market rates at September 30, 2004. If these derivative instruments had been terminated at September 30, 2004, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.

      The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2004 is estimated to be $16 million in ComEd’s favor. If the derivative instrument had been terminated at September 30, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.

      The aggregate fair value of the interest-rate swaps designated as fair-value hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at September 30, 2004 is estimated to be $1 million in ComEd’s favor. If the derivative instrument had been terminated at September 30, 2004, this estimated fair value represents the amount the counterparties would pay ComEd.

      In April 2004, ComEd settled certain interest-rate swaps designated as fair-value hedges in the aggregate amount of $485 million for total proceeds of approximately $32 million, which included the $26 million settlement amount and $6 million of accrued interest. The $26 million settlement amount will be amortized as a reduction to interest expense over the remaining life of the related debt.

	PECO

      As of September 30, 2004, a hypothetical 10% increase in the interest rates associated with variable-rate debt would not have a material impact on PECO’s pre-tax earnings.

      In March 2004, PECO entered into a forward-starting interest-rate swap in the aggregate amount of $75 million to lock in interest rate levels in anticipation of a future financing. The debt issuance that this swap was hedging was considered probable in March 2004 and closed in April 2004; therefore, PECO accounted for this interest-rate swap transaction as a hedge. In April 2004, PECO settled this interest-rate swap designated as a cash-flow hedge for net proceeds of approximately $5 million. The proceeds were recorded in other comprehensive income and are being amortized over the life of the debt issuance.

	Generation

      Generation uses a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Generation also uses interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. These strategies are employed to achieve a lower cost of capital. As of September 30, 2004, a hypothetical 10% increase in the interest rates associated with variable-rate debt would not have a material impact on Generation’s pre-tax earnings.

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Equity Price Risk

	Generation

      Generation maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2004, decommissioning trust funds are reflected at fair value on Generation’s 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 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 $297 million reduction in the fair value of the trust assets.

Item 4.	Controls and Procedures

      During the third quarter of 2004, 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 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, 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. Each registrant’s controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. A registrant’s access and ability to apply its disclosure controls and procedures to unconsolidated entities and entities that are consolidated under FIN No. 46-R may be more limited than is the case for majority-owned subsidiaries.

      Accordingly, as of September 30, 2004, 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. During the three months ended September 30, 2004, Exelon completed the implementation of an information technology system that supports the computation and tracking of deferred income tax balances. Exelon’s management believes this system implementation constitutes a material change in internal control over financial reporting.

      Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”) requires Exelon to include a report regarding the effectiveness of its internal control over financial reporting, beginning with its Annual Report on Form 10-K for the year ending December 31, 2004. That report is to include an assessment by Exelon’s management of the effectiveness of its internal control over financial reporting as of the end of the fiscal year along with an attestation report from Exelon’s independent auditors regarding that assessment. Accordingly, Exelon has undertaken a comprehensive effort to assess its system of internal controls over financial reporting. Using internal resources and external consulting assistance, Exelon has reviewed its internal controls over financial reporting to assess their adequacy and, as necessary, to address identified issues or inadequacies. That review has shown that, while most controls function appropriately, some areas require additional work and improvement. Although Exelon has not yet completed its assessment of its overall system of internal control, Exelon’s management does not believe that any of the identified areas constitute a “material weakness.” Exelon expects that these areas will be appropriately addressed by year-end 2004 and anticipates that they will

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PART II — OTHER INFORMATION

Item 1.	Legal Proceedings

ComEd

      See “Retail Rate Law” within the litigation section of Note 15 of the Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.

Generation

      See “Raytheon and Mitsubishi Litigation” and “Oyster Creek” within the litigation section of Note 15 of the Combined Notes to Consolidated Financial Statements and “Cotter Corporation Litigation” of Note 19 of the Combined Notes to Consolidated Financial Statements for a discussion of legal proceeding developments.

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

      (e) Exelon

      The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock. All share and per-share amounts included in the table below have been adjusted to reflect the stock split.

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, 2004

1,863

$

32.84

—

(b

)

August 1 — August 31, 2004

1,571

33.49

—

(b

)

September 1 — September 30, 2004

—

—

—

(b

)

Total

3,434

33.14

—

(b

)

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(a)		Shares other than those purchased as a 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.

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Item 5.	Other Information

      (a) ComEd, PECO and Generation

	Regulatory Issues (ComEd)

      See Note 7 of the Combined Notes to Consolidated Financial Statements and ComEd’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Overview” for a discussion of regulatory developments.

	Labor Relations (PECO)

      As previously reported in the 2003 Form 10-K, on August 15, 2002, the International Brotherhood of Electrical Workers (IBEW) filed a petition with the National Labor Relations Board (NLRB) to conduct a unionization vote of certain of PECO’s employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election were not certified due to pending challenges and objections. On March 22, 2004, the IBEW withdrew its objections to the May 21, 2003 election, and asked the NLRB to allow for a new election at PECO. On April 22, 2004, the NLRB granted IBEW’s request. A new election was held on July 21, 2004 that resulted in union representation for 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 have not yet begun negotiations for an initial agreement.

	Jointly Owned Electric Utility Plant (Generation)

      On January 28, 2004, the NRC issued a letter requesting Public Service Enterprise Group (PSEG) to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004, and had independent assessments of the work environment at the facility performed. Assessment results were provided to the NRC in May. The assessments concluded that Salem was safe for continued operation, but also identified issues that needed to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on a safety conscious work environment, the corrective action program, and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. PSEG will provide the NRC a report of its progress and discuss the progress of its actions to resolve identified issues at public meetings on December 2, 2004 and in 2005. PSEG will publish metrics to demonstrate performance commencing in the fourth quarter of 2004.

      In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed National Pollutant Discharge Elimination System permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the agency grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit would result in material costs of compliance to the owners of the facility.

173

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Item 6.	Exhibits

      (a) Exhibits:

2-1		—		Amended and Restated Agreement and Plan of Merger dated as of October 20, 2000, among PECO Energy Company, Exelon Corporation and Unicom Corporation (File No. 1-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).
3-1		—		Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1).
3-1-1		—		Amendment to Articles of Incorporation for Exelon Corporation effective as of April 19, 2004 (File No. 1-16169, Form 10-Q for the quarter ended June 30, 2004, Exhibit 3-1).
3-2		—		Amended and Restated Bylaws of Exelon Corporation, adopted January 27, 2004 (File No. 1-16169, 2003 Form 10-K, Exhibit 3-2).
3-3		—		Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).
3-4		—		Bylaws of PECO Energy Company, adopted February 26, 1990 and amended January 26, 1998 (File No. 1-01401, 1997 Form 10-K, Exhibit 3-2).
3-5		—		Restated Articles of Incorporation of Commonwealth Edison Company effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).
3-6		—		Bylaws of Commonwealth Edison Company, effective September 2, 1998, as amended through October 20, 2000 (File No. 1-1839, 2000 Form 10-K, Exhibit 3-6).
3-7		—		Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
3-8		—		First Amended and Restated Operating Agreement of Exelon Generation Company, LLC executed as of January 1, 2001 (File No. 333-85496, 2003 Form 10-K, Exhibit 3-8).
4-1		—		First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (First Union National Bank, successor), (Registration No. 2-2281, Exhibit B-1).
4-1-1		—		Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:

Dated as of		File Reference		Exhibit No.
May 1, 1927		2-2881			B-1(c)
March 1, 1937		2-2881			B-1(g)
December 1, 1941		2-4863			B-1(h)
November 1, 1944		2-5472			B-1(i)
December 1, 1946		2-6821			7-1(j)
September 1, 1957		2-13562			2(b)-17
May 1, 1958		2-14020			2(b)-18
March 1, 1968		2-34051			2(b)-24
March 1, 1981		2-72802			4-46
March 1, 1981		2-72802			4-47
December 1, 1984		1-01401, 1984 Form 10-K			4-2(b)
April 1, 1991		1-01401, 1991 Form 10-K			4(e)-76
December 1, 1991		1-01401, 1991 Form 10-K			4(e)-77
June 1, 1992		1-01401, June 30, 1992 Form 10-Q			4(e)-81
March 1, 1993		1-01401, 1992 Form 10-K			4(e)-86
May 1, 1993		1-01401, March 31, 1993 Form 10-Q			4(e)-88
May 1, 1993		1-01401, March 31, 1993 Form 10-Q			4(e)-89

174

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Dated as of		File Reference		Exhibit No.
August 15, 1993		1-01401, Form 8-A dated August 19, 1993			4(e)-92
May 1, 1995		1-01401, Form 8-K dated May 24, 1995			4(e)-96
September 15, 2002		1-01401, September 30, 2002 Form 10-Q			4-1
October 1, 2002		1-01401, September 30, 2002 Form 10-Q			4-2 4.1
April 15, 2003		0-16844, March 31, 2003 Form 10-Q
April 15, 2004

4-2		—		Exelon Corporation Dividend Reinvestment and Stock Purchase Plan (Registration Statement No. 333-84446, Form S-3, Prospectus).
4-3		—		Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1).
4-3-1		—		Supplemental Indentures to aforementioned Commonwealth Edison Mortgage.

Dated as of		File Reference				Exhibit No.
August 1, 1946			2-60201, Form S-7				2-1
April 1, 1953			2-60201, Form S-7				2-1
March 31, 1967			2-60201, Form S-7				2-1
April 1,1967			2-60201, Form S-7				2-1
February 28, 1969			2-60201, Form S-7				2-1
May 29, 1970			2-60201, Form S-7				2-1
June 1, 1971			2-60201, Form S-7				2-1
April 1, 1972			2-60201, Form S-7				2-1
May 31, 1972			2-60201, Form S-7				2-1
June 15, 1973			2-60201, Form S-7				2-1
May 31, 1974			2-60201, Form S-7				2-1
June 13, 1975			2-60201, Form S-7				2-1
May 28, 1976			2-60201, Form S-7				2-1
June 3, 1977			2-60201, Form S-7				2-1
May 17, 1978			2-99665, Form S-3				4-3
August 31, 1978			2-99665, Form S-3				4-3
June 18, 1979			2-99665, Form S-3				4-3
June 20, 1980			2-99665, Form S-3				4-3
April 16, 1981			2-99665, Form S-3				4-3
April 30, 1982			2-99665, Form S-3				4-3
April 15, 1983			2-99665, Form S-3				4-3
April 13, 1984			2-99665, Form S-3				4-3
April 15, 1985			2-99665, Form S-3				4-3
April 15, 1986			33-6879, Form S-3				4-9
June 15, 1990			33-38232, Form S-3				4-12
October 1, 1991			33-40018, Form S-3				4-13
October 15, 1991			33-40018, Form S-3				4-14
May 15, 1992			33-48542, Form S-3				4-14
September 15, 1992			33-53766, Form S-3				4-14
February 1, 1993			1-1839, 1992 Form 10-K				4-14

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Dated as of		File Reference				Exhibit No.
April 1, 1993			33-64028, Form S-3				4-12
April 15, 1993			33-64028, Form S-3				4-13
June 15, 1993			1-1839, Form 8-K dated May 21, 1993				4-1
July 15, 1993			1-1839, Form 10-Q for quarter ended June 30, 1993.				4-1
January 15, 1994			1-1839, 1993 Form 10-K				4-15
December 1, 1994			1-1839, 1994 Form 10-K				4-16
June 1, 1996			1-1839, 1996 Form 10-K				4-16
March 1, 2002			1-1839, 2001 Form 10-K				4-4-1
May 20, 2002			1-1839, 2001 Form 10-K				4-4-1
June 1, 2002			1-1839, 2001 Form 10-K				4-4-1
October 7, 2002			1-1839, 2001 Form 10-K				4-4-1
January 13, 2003			1-1839, Form 8-K dated January 22, 2003				4-4
March 14, 2003			1-1839, Form 8-K dated April 7, 2003				4-4
August 13, 2003			1-1839, Form 8-K dated August 25, 2003				4-4

4-3-2		—		Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2).
4-3-3		—		Instrument dated as of January 31, 1996, under the provisions of the Mortgage dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29).
4-4		—		Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A., Trustee relating to Notes (File No. 1-1839, Form S-3, Exhibit 4-13).
4-4-1		—		Supplemental Indentures to aforementioned Indenture.

Dated as of		File Reference				Exhibit No.
September 1, 1987			33-32929, Form S-3				4-16
January 1, 1997			1-1839, 1999 Form 10-K				4-21
September 1, 2000			1-1839, 2000 Form 10-K				4-7-3

4-5		—		Indenture dated June 1, 2001 between Generation and First Union National Bank (now Wachovia Bank, National Association) (Registration Statement No. 333-85496, Form S-4, Exhibit 4.1).
4-6		—		Indenture dated December 19, 2003 between Generation and Wachovia Bank, National Association (File No. 333-85496, 2003 Form 10-K, Exhibit 4-6).
4-7		—		Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and Wachovia Bank National Association, as Trustee (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.1).
4-8		—		Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and Wachovia Trust Company, National Association, as Trustee, dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.2).
4-9		—		PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, Wachovia Trust Company, National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.3).

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      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, 2004 filed by the following officers for the following companies:

31-1		—		Filed by John W. Rowe for Exelon Corporation
31-2		—		Filed by Robert S. Shapard for Exelon Corporation
31-3		—		Filed by John L. Skolds for Commonwealth Edison Company
31-4		—		Filed by J. Barry Mitchell for Commonwealth Edison Company
31-5		—		Filed by John L. Skolds for PECO Energy Company
31-6		—		Filed by J. Barry Mitchell for PECO Energy Company
31-7		—		Filed by John F. Young for Exelon Generation Company, LLC
31-8		—		Filed by J. Barry Mitchell 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, 2004 filed by the following officers for the following companies:

32-1		—		Filed by John W. Rowe for Exelon Corporation
32-2		—		Filed by Robert S. Shapard for Exelon Corporation
32-3		—		Filed by John L. Skolds for Commonwealth Edison Company
32-4		—		Filed by J. Barry Mitchell for Commonwealth Edison Company
32-5		—		Filed by John L. Skolds for PECO Energy Company
32-6		—		Filed by J. Barry Mitchell for PECO Energy Company
32-7		—		Filed by John F. Young for Exelon Generation Company, LLC
32-8		—		Filed by J. Barry Mitchell for Exelon Generation Company, LLC

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SIGNATURES

      Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION

/s/ JOHN W. ROWE John W. Rowe Chairman and Chief Executive Officer (Principal Executive Officer)		/s/ ROBERT S. SHAPARD Robert S. Shapard Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger Vice President and Corporate Controller (Principal Accounting Officer)

October 27, 2004

      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/ JOHN L. SKOLDS John L. Skolds President, Exelon Energy Delivery (Principal Executive Officer)		/s/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)
/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger Vice President and Corporate Controller, Exelon (Principal Accounting Officer)		/s/ FRANK M. CLARK Frank M. Clark President, ComEd

October 27, 2004

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      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/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)
/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger Vice President and Corporate Controller, Exelon (Principal Accounting Officer)		/s/ DENIS P. O’BRIEN Denis P. O’Brien President, PECO

October 27, 2004

      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 F. YOUNG John F. Young President (Principal Executive Officer)		/s/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)
/s/ JON D. VEURINK Jon D. Veurink Vice President and Controller (Principal Accounting Officer)

October 27, 2004

179

 

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CERTIFICATION EXHIBITS

Exhibit 31-1

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, John W. Rowe, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ JOHN W. ROWE Chairman and Chief Executive Officer (Principal Executive Officer)

 

\

Exhibit 31-2

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, Robert S. Shapard, certify that:
	1. I have reviewed this report on Form 10-Q of Exelon Corporation;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ ROBERT S. SHAPARD Executive Vice President and Chief Financial Officer (Principal Financial Officer)

 

Exhibit 31-3

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, John L. Skolds, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ JOHN L. SKOLDS President, Exelon Energy Delivery (Principal Executive Officer)

 

Exhibit 31-4

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, J. Barry Mitchell, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ J. BARRY MITCHELL Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

 

Exhibit 31-5

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, John L. Skolds, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ JOHN L. SKOLDS President, Exelon Energy Delivery (Principal Executive Officer)

 

Exhibit 31-6

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, J. Barry Mitchell, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ J. BARRY MITCHELL Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

 

Exhibit 31-7

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, John F. Young, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ JOHN F. YOUNG President (Principal Executive Officer)

 

Exhibit 31-8

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

	I, J. Barry Mitchell, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;
	2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2004		/s/ J. BARRY MITCHELL Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

 

Exhibit 32-1

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Exelon Corporation for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

Date: October 27, 2004		/s/ JOHN W. ROWE John W. Rowe Chairman and Chief Executive Officer

 

Exhibit 32-2

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Exelon Corporation for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

Date: October 27, 2004		/s/ ROBERT S. SHAPARD Robert S. Shapard Executive Vice President and Chief Financial Officer

 

Exhibit 32-3

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Commonwealth Edison Company for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

Date: October 27, 2004		/s/ JOHN L. SKOLDS John L. Skolds President Exelon Energy Delivery

 

Exhibit 32-4

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Commonwealth Edison Company for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

Date: October 27, 2004		/s/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer

 

Exhibit 32-5

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of PECO Energy Company for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

Date: October 27, 2004		/s/ JOHN L. SKOLDS John L. Skolds President Exelon Energy Delivery

 

Exhibit 32-6

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of PECO Energy Company for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

Date: October 27, 2004		/s/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer

 

Exhibit 32-7

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

Date: October 27, 2004		/s/ JOHN F. YOUNG John F. Young President

 

Exhibit 32-8

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

      The undersigned officer hereby certifies, as to the Quarterly Report on Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended September 30, 2004, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

Date: October 27, 2004		/s/ J. BARRY MITCHELL J. Barry Mitchell Senior Vice President, Treasurer and Chief Financial Officer