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 June 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 June 30, 2004 was:

Exelon Corporation Common Stock, without par value		660,149,965
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,486
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.

---

---

 

PAGE INTENTIONALLY LEFT BLANK

---

 

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			70
		Exelon Corporation			72
		Commonwealth Edison Company			110
		PECO Energy Company			126
		Exelon Generation Company, LLC			140
Item 3.		Quantitative and Qualitative Disclosure About Market Risk			157
Item 4.		Controls and Procedures			165
PART II.		OTHER INFORMATION			165
Item 1.		Legal Proceedings			165
		Exelon Corporation			165
		Commonwealth Edison Company			165
		Exelon Generation Company, LLC			165
Item 2.		Changes in Securities and Use of Proceeds			166
		Exelon Corporation			166
Item 4.		Submission of Matters to a Vote of Security Holders			166
		Exelon Corporation			166
		PECO Energy Company			166

1

---

 

				Page No.
Item 5.		Other Information			167
		Exelon Corporation			167
		Commonwealth Edison Company			167
		PECO Energy Company			167
		Exelon Generation Company, LLC			167
Item 6.		Exhibits and Reports on Form 8-K			168
SIGNATURES					170
		Exelon Corporation			170
		Commonwealth Edison Company			170
		PECO Energy Company			171
		Exelon Generation Company, LLC			171

2

---

 

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’ 2003 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’ 2003 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.

3

---

 

PAGE INTENTIONALLY LEFT BLANK

4

---

 

PART I. FINANCIAL INFORMATION

Item 1.     Financial Statements

5

---

 

EXELON CORPORATION

				Three Months								Six Months
				Ended June 30,								Ended June 30,
				2004				2003				2004				2003
(In millions, except per share data)
Operating revenues				$	3,550			$	3,721			$	7,272			$	7,795
Operating expenses
	Purchased power				673				746				1,234				1,586
	Purchased power from AmerGen Energy Company, LLC				—				110				—				177
	Fuel				538				531				1,374				1,356
	Operating and maintenance				1,056				1,100				2,165				2,212
	Depreciation and amortization				315				275				616				549
	Taxes other than income				185				159				378				358
		Total operating expenses			2,767				2,921				5,767				6,238
Operating income					783				800				1,505				1,557
Other income and deductions
	Interest expense				(156	)			(217	)			(286	)			(437	)
	Interest expense to affiliates				(90	)			(3	)			(183	)			(6	)
	Distributions on preferred securities of subsidiaries				(1	)			(10	)			(2	)			(22	)
	Equity in earnings (losses) of unconsolidated affiliates				(31	)			15				(55	)			33
	Other, net				230				10				287				(131	)
		Total other income and deductions			(48	)			(205	)			(239	)			(563	)
Income before income taxes, minority interest and cumulative effect of changes in accounting principles					735				595				1,266				994
Income taxes					226				222				376				370
Income before minority interest and cumulative effect of changes in accounting principles					509				373				890				624
Minority interest					12				(1	)			11				(3	)
Income before cumulative effect of changes in accounting principles					521				372				901				621
Cumulative effect of changes in accounting principles (net of income taxes of $22 and $69 for the six months ended June 30, 2004 and 2003, respectively)					—				—				32				112
Net income					521				372				933				733
Other comprehensive income (loss) (net of income taxes)
	Change in net unrealized gain (loss) on cash-flow hedges				50				62				(154	)			(84	)
	Foreign currency translation adjustment				(4	)			1				(2	)			2
	Unrealized gain (loss) on marketable securities				(31	)			3				22				(2	)
	SFAS No. 143 transition adjustment				—				—				—				168
	Interest in other comprehensive income (loss) of unconsolidated affiliates				—				17				(8	)			8
		Total other comprehensive income (loss)			15				83				(142	)			92
Total comprehensive income				$	536			$	455			$	791			$	825
Average shares of common stock outstanding — Basic					661				650				660				649
Average shares of common stock outstanding — Diluted					667				655				666				653
Earnings per average common share — Basic:
	Income before cumulative effect of changes in accounting principles			$	0.79			$	0.57			$	1.36			$	0.96
	Cumulative effect of changes in accounting principles				—				—				0.05				0.17
	Net income			$	0.79			$	0.57			$	1.41			$	1.13
Earnings per average common share — Diluted:
	Income before cumulative effect of changes in accounting principles			$	0.78			$	0.57			$	1.35			$	0.95
	Cumulative effect of changes in accounting principles				—				—				0.05				0.17
	Net income			$	0.78			$	0.57			$	1.40			$	1.12
Dividends per common share				$	0.28			$	0.23			$	0.55			$	0.46

See Combined Notes to Consolidated Financial Statements

6

---

 

EXELON CORPORATION AND SUBSIDIARY COMPANIES

					Six Months
					Ended June 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	933			$	733
	Adjustments to reconcile net income to net cash flows provided by operating activities
		Depreciation, amortization and accretion, including nuclear fuel				930				846
		Cumulative effect of changes in accounting principles (net of income taxes)				(32	)			(112	)
		Impairment of investments				1				238
		Impairment of goodwill and other long-lived assets				—				53
		Deferred income taxes and amortization of investment tax credits				154				(100	)
		Provision for uncollectible accounts				39				43
		Equity in losses (earnings) of unconsolidated affiliates				55				(33	)
		Gains on sales of investments and wholly-owned subsidiaries				(155	)			—
		Net realized losses (gains) on nuclear decommissioning trust funds				1				(12	)
		Other operating activities				(16	)			52
		Changes in assets and liabilities
			Receivables			269				70
			Inventories			14				(16	)
			Other current assets			(66	)			(219	)
			Accounts payable, accrued expenses and other current liabilities			(134	)			(143	)
			Net realized and unrealized mark-to-market and hedging transactions			54				76
			Pension and non-pension postretirement benefits obligations			(175	)			(146	)
			Other noncurrent assets and liabilities			35				(38	)
Net cash flows provided by operating activities						1,907				1,292
Cash flows from investing activities
	Capital expenditures					(844	)			(1,019	)
	Proceeds from liquidated damages					—				86
	Proceeds from nuclear decommissioning trust fund sales					1,042				1,262
	Investment in nuclear decommissioning trust funds					(1,178	)			(1,368	)
	Note receivable from unconsolidated affiliate					—				35
	Proceeds from sales of investments and wholly-owned subsidiaries					227				6
	Change in restricted cash					(2	)			(29	)
	Net cash increase from consolidation of Sithe Energies, Inc.					19				—
	Other investing activities					67				11
Net cash flows used in investing activities						(669	)			(1,016	)
Cash flows from financing activities
	Issuance of long-term debt					75				1,813
	Retirement of long-term debt					(312	)			(1,479	)
	Retirement of long-term debt to financing affiliates					(345	)			—
	Change in short-term debt					(65	)			(100	)
	Issuance of mandatorily redeemable preferred securities					—				300
	Retirement of mandatorily redeemable preferred securities					—				(300	)
	Payment on acquisition note payable to Sithe Energies, Inc.					(27	)			(210	)
	Dividends paid on common stock					(364	)			(285	)
	Proceeds from employee stock plans					140				91
	Purchase of treasury stock					(75	)			—
	Other financing activities					36				(85	)
Net cash flows used in financing activities						(937	)			(255	)
Increase in cash and cash equivalents						301				21
Cash and cash equivalents at beginning of period						493				469
Cash and cash equivalents, including cash classified as held for sale						794				490
Cash classified as held for sale on the consolidated balance sheet						—				(26	)
Cash and cash equivalents at end of period					$	794			$	464
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			$	—

See Combined Notes to Consolidated Financial Statements

7

---

 

EXELON CORPORATION AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	794			$	493
	Restricted cash and investments				179				97
	Accounts receivable, net
		Customer			1,645				1,567
		Other			403				582
	Mark-to-market derivative assets				433				337
	Inventories, at average cost
		Fossil fuel			165				212
		Materials and supplies			318				310
	Notes receivable from affiliate				—				92
	Deferred income taxes				145				162
	Assets held for sale				20				242
	Other				449				413
		Total current assets			4,551				4,507
Property, plant and equipment, net					20,228				20,630
Deferred debits and other assets
	Regulatory assets				5,038				5,226
	Nuclear decommissioning trust funds				4,890				4,721
	Investments				922				955
	Goodwill				4,714				4,719
	Mark-to-market derivative assets				391				133
	Other				1,368				991
		Total deferred debits and other assets			17,323				16,745
Total assets				$	42,102			$	41,882

See Combined Notes to Consolidated Financial Statements

8

---

 

EXELON CORPORATION AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Commercial paper			$	261			$	326
	Note payable to Sithe Energies, Inc.				—				90
	Long-term debt due within one year				177				1,385
	Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year				478				470
	Accounts payable				1,221				1,238
	Mark-to-market derivative liabilities				805				584
	Accrued expenses				1,080				1,166
	Liabilities held for sale				14				61
	Other				293				306
		Total current liabilities			4,329				5,626
Long-term debt					8,672				7,889
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust					4,702				5,055
Long-term debt to other financing trusts					545				545
Deferred credits and other liabilities
	Deferred income taxes				4,580				4,360
	Unamortized investment tax credits				281				288
	Asset retirement obligation				3,100				2,997
	Pension obligations				1,445				1,668
	Non-pension postretirement benefits obligations				1,102				1,053
	Spent nuclear fuel obligation				872				867
	Regulatory liabilities				1,967				1,891
	Mark-to-market derivative liabilities				425				141
	Other				919				912
		Total deferred credits and other liabilities			14,691				14,177
		Total liabilities			32,939				33,292
Commitments and contingencies
Minority interest of consolidated subsidiaries					50				—
Preferred securities of subsidiaries					87				87
Shareholders’ equity
	Common stock				7,463				7,292
	Treasury stock, at cost				(75	)			—
	Retained earnings				2,889				2,320
	Accumulated other comprehensive income (loss)				(1,251	)			(1,109	)
		Total shareholders’ equity			9,026				8,503
Total liabilities and shareholders’ equity				$	42,102			$	41,882

See Combined Notes to Consolidated Financial Statements

9

---

 

COMMONWEALTH EDISON COMPANY

				Three Months								Six Months
				Ended June 30,								Ended June 30,
				2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues			$	1,397			$	1,345			$	2,722			$	2,756
	Operating revenues from affiliates				6				16				17				29
		Total operating revenues			1,403				1,361				2,739				2,785
Operating expenses
	Purchased power				60				5				65				11
	Purchased power from affiliate				514				528				1,043				1,099
	Operating and maintenance				178				197				348				431
	Operating and maintenance from affiliates				45				24				90				52
	Depreciation and amortization				103				96				205				190
	Taxes other than income				72				68				151				148
		Total operating expenses			972				918				1,902				1,931
Operating income					431				443				837				854
Other income and deductions
	Interest expense				(68	)			(106	)			(144	)			(215	)
	Interest expense to affiliates				(28	)			—				(58	)			—
	Distributions on mandatorily redeemable preferred securities				—				(6	)			—				(14	)
	Equity in (losses) of unconsolidated affiliates				(6	)			—				(9	)			—
	Interest income from affiliates				5				7				11				13
	Other, net				2				5				6				21
		Total other income and deductions			(95	)			(100	)			(194	)			(195	)
Income before income taxes and cumulative effect of a change in accounting principle					336				343				643				659
Income taxes					132				138				255				263
Income before cumulative effect of a change in accounting principle					204				205				388				396
Cumulative effect of a change in accounting principle (net of income taxes of $0)					—				—				—				5
Net income					204				205				388				401
Other comprehensive income (loss) (net of income taxes)
	Change in net unrealized gain (loss) on cash-flow hedges				—				(3	)			—				28
	Unrealized gain on marketable securities				—				1				—				1
	Foreign currency translation adjustment				—				1				—				2
		Total other comprehensive income (loss)			—				(1	)			—				31
Total comprehensive income				$	204			$	204			$	388			$	432

See Combined Notes to Consolidated Financial Statements

10

---

 

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

					Six Months
					Ended June 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	388			$	401
	Adjustments to reconcile net income to net cash flows provided by operating activities
		Depreciation and amortization				205				190
		Cumulative effect of a change in accounting principle (net of income taxes)				—				(5	)
		Deferred income taxes and amortization of investment tax credits				86				60
		Provision for uncollectible accounts				16				20
		Equity in losses of unconsolidated affiliates				9				—
		Other operating activities				24				25
		Changes in assets and liabilities
			Receivables			(38	)			9
			Inventories			(1	)			2
			Accounts payable, accrued expenses and other current liabilities			12				(115	)
			Receivables and payables to affiliates			15				(155	)
			Other current assets			5				(2	)
			Pension and non-pension postretirement benefits obligations			(93	)			(72	)
			Other noncurrent assets and liabilities			(26	)			11
Net cash flows provided by operating activities						602				369
Cash flows from investing activities
	Capital expenditures					(369	)			(355	)
	Changes in Exelon intercompany money pool investment					207				(165	)
	Change in restricted cash					18				(18	)
	Other investing activities					11				14
Net cash flows used in investing activities						(133	)			(524	)
Cash flows from financing activities
	Issuance of long-term debt					—				1,135
	Retirement of long-term debt					(178	)			(662	)
	Retirement of long-term debt to ComEd Transitional Funding Trust					(179	)			—
	Issuance of mandatorily redeemable preferred securities					—				200
	Retirement of mandatorily redeemable preferred securities					—				(200	)
	Change in short-term debt					—				(71	)
	Dividends paid on common stock					(207	)			(211	)
	Contributions from parent					62				61
	Settlement of cash-flow and fair-value hedges					26				(51	)
	Other financing activities					—				(28	)
Net cash flows (used in) provided by financing activities						(476	)			173
(Decrease) increase in cash and cash equivalents						(7	)			18
Cash and cash equivalents at beginning of period						34				16
Cash and cash equivalents at end of period					$	27			$	34
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

11

---

 

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	27			$	34
	Restricted cash				2				20
	Accounts receivable, net
		Customer			720				683
		Other			53				68
	Inventories, at average cost				44				43
	Deferred income taxes				5				6
	Receivables from affiliates				22				23
	Investment in Exelon intercompany money pool				198				405
	Other				26				31
		Total current assets			1,097				1,313
Property, plant and equipment, net					9,288				9,096
Deferred debits and other assets
	Investments				37				36
	Investment in affiliates				63				73
	Goodwill				4,714				4,719
	Receivables from affiliates				2,300				2,271
	Pension asset				117				4
	Other				394				453
		Total deferred debits and other assets			7,625				7,556
Total assets				$	18,010			$	17,965

See Combined Notes to Consolidated Financial Statements

12

---

 

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Long-term debt due within one year			$	59			$	236
	Long-term debt to ComEd Transitional Funding Trust due within one year				307				317
	Accounts payable				184				170
	Accrued expenses				526				540
	Payables to affiliates				222				207
	Customer deposits				80				78
	Other				12				9
		Total current liabilities			1,390				1,557
Long-term debt					4,158				4,167
Long-term debt to ComEd Transitional Funding Trust					1,190				1,359
Long-term debt to other affiliates					361				361
Deferred credits and other liabilities
	Deferred income taxes				1,775				1,686
	Unamortized investment tax credits				47				48
	Non-pension postretirement benefits obligation				210				190
	Payables to affiliates				27				28
	Regulatory liabilities				1,967				1,891
	Other				300				336
		Total deferred credits and other liabilities			4,326				4,179
		Total liabilities			11,425				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				(188	)			(250	)
	Retained earnings				1,064				883
	Accumulated other comprehensive income (loss)				(1	)			(1	)
		Total shareholders’ equity			6,585				6,342
Total liabilities and shareholders’ equity				$	18,010			$	17,965

See Combined Notes to Consolidated Financial Statements

13

---

 

PECO ENERGY COMPANY

					Three Months								Six Months
					Ended June 30,								Ended June 30,
					2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues				$	1,027			$	958			$	2,262			$	2,173
	Operating revenues from affiliates					5				3				9				5
			Total operating revenues			1,032				961				2,271				2,178
Operating expenses
	Purchased power					53				62				100				127
	Purchased power from affiliate					349				324				699				681
	Fuel					76				67				325				257
	Fuel from affiliate					7				—				7				—
	Operating and maintenance					104				110				215				236
	Operating and maintenance from affiliates					28				11				51				25
	Depreciation and amortization					125				116				250				236
	Taxes other than income					60				47				118				110
			Total operating expenses			802				737				1,765				1,672
Operating income						230				224				506				506
Other income and deductions
	Interest expense					(14	)			(83	)			(28	)			(168	)
	Interest expense to affiliates					(62	)			—				(125	)			—
	Distributions on mandatorily redeemable preferred securities					—				(2	)			—				(5	)
	Equity in losses of unconsolidated affiliates					(7	)			—				(13	)			—
	Other, net					3				1				5				10
			Total other income and deductions			(80	)			(84	)			(161	)			(163	)
Income before income taxes						150				140				345				343
Income taxes						50				52				112				119
Net income						100				88				233				224
Preferred stock dividends						1				2				2				3
Net income on common stock					$	99			$	86			$	231			$	221
Other comprehensive income (net of income taxes)
	Net income				$	100			$	88			$	233			$	224
	Other comprehensive income (net of income taxes):
		Change in net unrealized gain on cash-flow hedges				2				—				3				—
		Unrealized gain on marketable securities				—				—				1				—
			Total other comprehensive income			2				—				4				—
Total comprehensive income					$	102			$	88			$	237			$	224

See Combined Notes to Consolidated Financial Statements

14

---

 

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

					Six Months
					Ended June 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	233			$	224
	Adjustments to reconcile net income to net cash flows provided by operating activities
		Depreciation and amortization				250				236
		Deferred income taxes and amortization of investment tax credits				(95	)			(28	)
		Provision for uncollectible accounts				19				21
		Equity in losses of unconsolidated affiliates				13				—
		Other operating activities				(4	)			5
		Changes in assets and liabilities
			Receivables			21				48
			Receivables and payables to affiliates			21				27
			Inventories			24				(1	)
			Accounts payable, accrued expenses and other current liabilities			56				11
			Prepaid taxes			(96	)			(91	)
			Deferred energy costs			56				(24	)
			Other current assets			(2	)			(4	)
			Pension and non-pension postretirement benefits obligations			15				16
			Other noncurrent assets and liabilities			(2	)			(15	)
Net cash flows provided by operating activities						509				425
Cash flows from investing activities
	Capital expenditures					(105	)			(132	)
	Changes in Exelon intercompany money pool investment					(35	)			—
	Change in restricted cash					—				28
	Other investing activities					3				6
Net cash flows used in investing activities						(137	)			(98	)
Cash flows from financing activities
	Issuance of long-term debt					75				450
	Retirement of long-term debt					(75	)			(592	)
	Retirement of long-term debt to PECO Energy Transition Trust					(166	)			—
	Change in short-term debt					(46	)			(30	)
	Issuance of mandatorily redeemable preferred securities					—				100
	Retirement of mandatorily redeemable preferred securities					—				(50	)
	Retirement of preferred stock					—				(50	)
	Dividends paid on preferred and common stock					(182	)			(168	)
	Contribution from parent					71				17
	Other financing activities					6				(6	)
Net cash flows used in financing activities						(317	)			(329	)
Increase (decrease) in cash and cash equivalents						55				(2	)
Cash and cash equivalents at beginning of period						44				63
Cash and cash equivalents at end of period					$	99			$	61

See Combined Notes to Consolidated Financial Statements

15

---

 

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	99			$	44
	Accounts receivable, net
		Customer			318				363
		Other			32				27
	Inventories, at average cost
		Gas			76				99
		Materials and supplies			6				7
	Investment in Exelon intercompany money pool				35				—
	Deferred income taxes				81				64
	Deferred energy costs				25				81
	Prepaid taxes				97				1
	Other				12				10
		Total current assets			781				696
Property, plant and equipment, net					4,286				4,256
Deferred debits and other assets
	Regulatory assets				5,038				5,226
	Investments				20				20
	Investment in affiliates				114				123
	Receivables from affiliates				35				13
	Pension asset				76				68
	Other				10				8
		Total deferred debits and other assets			5,293				5,458
Total assets				$	10,360			$	10,410

See Combined Notes to Consolidated Financial Statements

16

---

 

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
	Commercial paper			$	—			$	46
	Payables to affiliates				170				150
	Long-term debt to PECO Energy Transition Trust due within one year				171				153
	Accounts payable				74				92
	Accrued expenses				310				237
	Other				36				35
		Total current liabilities			761				713
Long-term debt					1,360				1,359
Long-term debt to PECO Energy Transition Trust					3,512				3,696
Long-term debt to other affiliates					184				184
Deferred credits and other liabilities
	Deferred income taxes				2,925				2,986
	Unamortized investment tax credits				20				22
	Non-pension postretirement benefits obligation				310				287
	Other				146				147
		Total deferred credits and other liabilities			3,401				3,442
		Total liabilities			9,218				9,394
Commitments and contingencies
Shareholders’ equity
	Common stock				2,000				1,999
	Receivable from parent				(1,553	)			(1,623	)
	Preferred stock				87				87
	Retained earnings				597				546
	Accumulated other comprehensive income				11				7
		Total shareholders’ equity			1,142				1,016
Total liabilities and shareholders’ equity				$	10,360			$	10,410

See Combined Notes to Consolidated Financial Statements

17

---

 

EXELON GENERATION COMPANY, LLC

					Three Months								Six Months
					Ended June 30,								Ended June 30,
					2004				2003				2004				2003
(In millions)
Operating revenues
	Operating revenues				$	1,077			$	990			$	2,150			$	1,876
	Operating revenues from affiliates					871				896				1,750				1,889
		Total operating revenues				1,948				1,886				3,900				3,765
Operating expenses
	Purchased power					560				675				1,069				1,436
	Purchased power from affiliates					3				125				12				206
	Fuel					462				348				1,048				706
	Operating and maintenance					554				411				1,139				861
	Operating and maintenance from affiliates					69				40				134				82
	Depreciation and amortization					69				46				124				91
	Taxes other than income					48				40				95				88
		Total operating expenses				1,765				1,685				3,621				3,470
Operating income						183				201				279				295
Other income and deductions
	Interest expense					(50	)			(16	)			(75	)			(30	)
	Interest expense to affiliates					(1	)			(4	)			(2	)			(8	)
	Equity in earnings (losses) of unconsolidated affiliates					—				18				(2	)			37
	Other, net					134				34				183				(132	)
		Total other income and deductions				83				32				104				(133	)
Income before income taxes, minority interest and cumulative effect of changes in accounting principles						266				233				383				162
Income taxes						100				91				146				71
Income before minority interest and cumulative effect of changes in accounting principles						166				142				237				91
Minority interest						12				—				11				(2	)
Income before cumulative effect of changes in accounting principles						178				142				248				89
Cumulative effect of changes in accounting principles (net of income taxes of $22 and $70 for the six months ended June 30, 2004 and 2003, respectively)						—				—				32				108
Net income						178				142				280				197
	Other comprehensive income (loss) (net of income taxes)
		Change in net unrealized gain (loss) on cash-flow hedges				48				64				(147	)			(116	)
		Unrealized gain (loss) on marketable securities				(31	)			2				8				(3	)
		Foreign currency translation adjustment				(4	)			—				(4	)			—
		SFAS No. 143 transition adjustment				—				—				—				168
		Interest in other comprehensive income of unconsolidated affiliates				—				17				2				8
			Total other comprehensive income (loss)			13				83				(141	)			57
Total comprehensive income					$	191			$	225			$	139			$	254

     See Combined Notes to Consolidated Financial Statements

18

---

 

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

					Six Months
					Ended June 30,
					2004				2003
(In millions)
Cash flows from operating activities
	Net income				$	280			$	197
	Adjustments to reconcile net income to net cash flows provided by operating activities
		Depreciation, amortization and accretion, including nuclear fuel				438				388
		Cumulative effect of changes in accounting principles (net of income taxes)				(32	)			(108	)
		Gain on sale of investment				(90	)			—
		Impairment of investment				—				200
		Impairment of long-lived assets				—				5
		Deferred income taxes and amortization of investment tax credits				148				(107	)
		Provision for uncollectible accounts				2				1
		Equity in (earnings) losses of unconsolidated affiliates				2				(37	)
		Net realized losses (gains) on nuclear decommissioning trust funds				1				(12	)
		Other operating activities				15				1
		Changes in assets and liabilities
			Receivables			(108	)			(112	)
			Receivables and payables to affiliates, net			(35	)			238
			Inventories			(10	)			(19	)
			Accounts payable, accrued expenses and other current liabilities			24				10
			Other current assets			(15	)			(104	)
			Net realized and unrealized mark-to-market and hedging transactions			39				76
			Pension and non-pension postretirement benefits obligations			(59	)			(59	)
			Other noncurrent assets and liabilities			16				(19	)
Net cash flows provided by operating activities						616				539
Cash flows from investing activities
	Capital expenditures					(366	)			(510	)
	Proceeds from liquidated damages					—				86
	Proceeds from nuclear decommissioning trust fund sales					1,042				1,262
	Investment in nuclear decommissioning trust funds					(1,178	)			(1,368	)
	Note receivable from affiliate					—				35
	Net cash increase from consolidation of Sithe Energies, Inc. and Exelon Energy Company					24				—
	Change in restricted cash					(18	)			(38	)
	Other investing activities					58				(1	)
Net cash flows used in investing activities						(438	)			(534	)
Cash flows from financing activities
	Issuance of long-term debt					—				211
	Retirement of long-term debt					(4	)			(3	)
	Change in short-term debt					211				—
	Payment on acquisition note payable to Sithe Energies, Inc.					(27	)			(210	)
	Changes in Exelon intercompany money pool borrowings					(218	)			165
	Change in note payable, affiliate					—				(107	)
	Distribution to member					(109	)			(45	)
	Other financing activities					6				—
Net cash flows (used in) provided by financing activities						(141	)			11
Increase in cash and cash equivalents						37				16
Cash and cash equivalents at beginning of period						158				58
Cash and cash equivalents at end of period					$	195			$	74
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

---

 

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
ASSETS
Current assets
	Cash and cash equivalents			$	195			$	158
	Restricted cash				173				75
	Accounts receivable, net
		Customer			575				389
		Other			444				402
	Mark-to-market derivative assets				433				322
	Receivables from affiliates				335				421
	Inventories, at average cost
		Fossil fuel			90				98
		Materials and supplies			267				259
	Notes receivable				6				5
	Deferred income taxes				43				40
	Assets held for sale				9				36
	Other				222				233
		Total current assets			2,792				2,438
Property, plant and equipment, net					6,493				7,106
Deferred debits and other assets
	Nuclear decommissioning trust funds				4,890				4,721
	Investments				98				65
	Receivable from affiliate				22				22
	Pension asset				173				79
	Mark-to-market derivative asset				390				100
	Other				544				118
		Total deferred debits and other assets			6,117				5,105
Total assets				$	15,402			$	14,649

See Combined Notes to Consolidated Financial Statements

20

---

 

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

				June 30,				December 31,
				2004				2003
(In millions)
Liabilities and member’s equity
Current liabilities
	Long-term debt due within one year			$	61			$	1,068
	Commercial paper				211				—
	Accounts payable				906				848
	Mark-to-market derivative liabilities				805				581
	Payables to affiliates				32				1
	Notes payable to affiliates				198				506
	Accrued expenses				401				423
	Liabilities held for sale				3				—
	Other				99				126
		Total current liabilities			2,716				3,553
Long-term debt					2,469				1,649
Deferred credits and other liabilities
	Deferred income taxes				378				195
	Unamortized investment tax credits				214				218
	Asset retirement obligation				3,099				2,996
	Pension obligation				20				21
	Non-pension postretirement benefits obligation				592				555
	Spent nuclear fuel obligation				872				867
	Payable to affiliates				1,247				1,195
	Mark-to-market derivative liabilities				425				133
	Other				331				308
		Total deferred credits and other liabilities			7,178				6,488
		Total liabilities			12,363				11,690
Commitments and contingencies
Minority interest of consolidated subsidiary					52				3
Member’s equity
	Membership interest				2,495				2,490
	Undistributed earnings				773				602
	Accumulated other comprehensive loss				(281	)			(136	)
		Total member’s equity			2,987				2,956
Total liabilities and member’s equity				$	15,402			$	14,649

See Combined Notes to Consolidated Financial Statements

21

---

 

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 enterprises businesses discussed below (see Note 17 — Segment Information). The energy delivery business segment consists of the purchase and sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by 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 segment consists of the electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation) and Generation’s equity interest in EXRES SHC, Inc., the holding company of Sithe Energies, Inc. and its subsidiaries, referred to herein as Sithe. Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. As of June 30, 2004, the enterprises business segment consists of the energy, infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments related to the communications, energy services and retail services industries. See Note 3 — Acquisitions and Dispositions for further 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 June 30, 2004 and for the three and six 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

---

 

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 June 30, 2004 and December 31, 2003 as follows:

		June 30, 2004				December 31, 2003
Exelon		$	5,725			$	6,070
ComEd			1,858				2,037
PECO			3,867				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

---

 

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 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 $239 million of revenue, $238 million of purchased power and $1 million of fuel expense net within revenues during the three months ended June 30, 2004 and $452 million of revenue, $444 million of purchased power and $8 million of fuel expense net within revenues during the six months ended June 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 June 30, 2003		As Reported				Impact				Pro Forma
Operating revenue		$	3,721			$	(234	)		$	3,487
Purchased power			856				(216	)			640
Fuel expense			531				(18	)			513

24

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

						EITF 03-11
For the Six Months Ended June 30, 2003		As Reported				Impact				Pro Forma
Operating revenue		$	7,795			$	(485	)		$	7,310
Purchased power			1,763				(448	)			1,315
Fuel expense			1,356				(37	)			1,319

	Generation

						EITF 03-11
For the Three Months Ended June 30, 2003		As Reported				Impact				Pro Forma
Operating revenue		$	1,886			$	(234	)		$	1,652
Purchased power			800				(216	)			584
Fuel expense			348				(18	)			330

						EITF 03-11
For the Six Months Ended June 30, 2003		As Reported				Impact				Pro Forma
Operating revenue		$	3,765			$	(485	)		$	3,280
Purchased power			1,642				(448	)			1,194
Fuel expense			706				(37	)			669

	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 remeasurement 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

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

		Three Months Ended				Six Months Ended
		June 30, 2004				June 30, 2004
Amortization of the actuarial experience gain		$	4			$	8
Reduction in current period service cost			1				2
Reduction in interest cost on the APBO			3				6

      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 was 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 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.

	EITF 03-01

      In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-01, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-01). EITF 03-01 provides guidance for evaluating whether an investment is other-than-temporarily impaired and

26

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

will be applied in other-than-temporary impairment evaluations made by Exelon beginning in the third quarter of 2004. Exelon adopted the disclosure requirements of EITF 03-01 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. For all other investments within the scope of EITF 03-01 and for cost method investments, the disclosures will be effective for Exelon for the year ended December 31, 2004. Comparative information for periods prior to initial application is not required. Exelon, ComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-01.

	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 will be effective for Exelon, ComEd, PECO and Generation during the third quarter of 2004. Exelon, ComEd, PECO and Generation are still evaluating the potential impact of the adoption of EITF 03-16.

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 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 will be transferred to the lenders’ special purpose entity in a separate transaction. Certain aspects of the transfer of operations and marketing are also subject to approval of the FERC. On June 24, 2004, the parties filed an application with the FERC for an order authorizing the transfer of responsibility for plant operations and power marketing, and the parties expect to complete that transfer during the third quarter of 2004. Pending completion of the transfer of operations and marketing activities, Generation affiliates will continue to operate and market power from the plants on behalf of the owners. Due to ongoing power marketing agreements between Generation and Boston Generating, 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. Exelon and Generation are hedged to eliminate the financial effects of these power-marketing-agreements from their results of operations.

      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.

27

---

 

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 a guarantee by their subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. 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 six months ended June 30, 2004 and 2003 include the following financial results related to Boston Generating:

		Three Months								Six Months
		Ended June 30,								Ended June 30,
		2004				2003				2004				2003
Operating revenues		$	89			$	130			$	248			$	183
Operating income (loss)			(15	)			(10	)			(47	)			8
Net income (loss)(a)			42				(8	)			24				3

---

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

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

	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. A pre-tax gain of $45 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. Enterprises repaid $37 million of debt outstanding of the Chicago thermal operations prior to closing, resulting in prepayment penalties of $9 million, which were recorded in interest expense.

      Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Exelon Services, Inc. (Services), including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale (before income taxes) recorded during the six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004,

28

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group. See Assets and Liabilities Held for Sale below for information regarding the classification of the assets and liabilities of the remaining business of Services as held for sale as of June 30, 2004.

      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. Enterprises’ results of operations for the three and six months ended June 30, 2004 compared to the same periods in 2003 were significantly affected by the sale of InfraSource.

      The results of Exelon 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 and liabilities of Exelon Energy Company that were transferred to Generation as of January 1, 2004:

Current assets (including $5 million of cash)		$	89
Property, plant and equipment			2
Deferred debits and other assets			13
Current liabilities			(96	)
Deferred credits and other liabilities			(10	)
Accumulated other comprehensive loss			(2	)
Member’s equity			4

      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 related to the

29

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

valuation of long-lived assets will be affected by the finalization of the purchase price based on the completion of the review of the closing AmerGen balances at December 31, 2003.

      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 six months ended June 30, 2003, Generation recorded $20 million and $84 million, respectively, of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $110 million and $177 million, respectively, of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $311 million. For the six months ended June 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)

      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. These facilities are not consolidated within Exelon’s financial statements because Exelon does not have a controlling financial interest in these facilities. The notes payable recorded for the purchase of the facilities was $238 million. Exelon’s right to acquire its share of tax credits generated by the facilities was recorded as an intangible asset and will be amortized as the tax credits are earned. Synthetic fuel facilities chemically change coal, including waste and marginal coal, into a fuel used at power plants. 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. See Note 19 — Subsequent Events for information regarding investments in synthetic fuel-producing facilities that occurred in July 2004.

	Assets and Liabilities Held for Sale (Exelon and Generation)

      The major classes of assets and liabilities classified as held for sale within Exelon’s and Generation’s Consolidated Balance Sheets as of June 30, 2004 consisted of the following:

		Generation				Enterprises				Exelon
Accounts receivable, net		$	—			$	8			$	8
Other current assets			—				2				2
Property, plant and equipment, net			9				1				10
Assets classified as held for sale		$	9			$	11			$	20

		Generation				Enterprises				Exelon
Accounts payable, accrued expenses and other current liabilities		$	—			$	11			$	11
Debt			3				—				3
Liabilities classified as held for sale		$	3			$	11			$	14

      Generation. Generation classified certain assets and liabilities of Sithe as held for sale as of June 30, 2004. Sithe is consolidated within the financial statements of Generation pursuant to FIN No. 46-R. During

30

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the three months ended June 30, 2004, Sithe completed the sale of its gas and Australian businesses, which represented $151 million and $140 million of assets and liabilities held for sale, respectively, at March 31, 2004.

      Enterprises. Enterprises classified the assets and liabilities of certain Services businesses as held for sale as of June 30, 2004 due to ongoing efforts to dispose of these businesses. These businesses are expected to be sold in 2004. See “Disposition of Enterprises Entities” above for further information.

4.	Sithe (Exelon and Generation)

      Sithe is primarily engaged in the development, construction, ownership and operation of electric wholesale generating facilities in North America. At June 30, 2004, excluding assets held for sale, Sithe operated nine power plants with total average net capacity of 1,323 megawatts (MW). Sithe also has 49.5% interests in two 230-MW projects in Mexico, which commenced commercial operations during the second quarter of 2004.

      The financial statements of all 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.

      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). Generation’s intent is to fully divest its interest in Sithe. See the 2003 Form 10-K for further details regarding these transactions.

      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 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’s 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 using a method that reflects the pattern in which the economic benefits of the intangible assets are consumed or used up in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), not to exceed the

31

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

terms of the related contracts. The allocation of fair value related to the valuation of long-lived assets is preliminary and is anticipated to be finalized in the third quarter of 2004.

      Sithe’s intangible assets are subject to amortization and are included in other non-current assets on Generation’s Consolidated Balance Sheet. Amortization expense for intangible assets was $15 million for the three months ended June 30, 2004. The components of Sithe’s intangible assets at June 30, 2004 were as follows:

						Accumulated
		Gross Carrying				Amortization				Intangible
Agreement Type		Amount				June 30, 2004				Asset, net
Energy Purchase Agreement		$	376			$	13			$	363
Tolling Agreement			71				2				69
Total		$	447			$	15			$	432

      Annual amortization expense for intangible assets is estimated to be $43 million for 2004, $58 million for 2005, $56 million for 2006, $50 million for 2007, and $44 million for 2008.

      In connection with the consolidation of Sithe, certain indemnification guarantees, which were 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), at Generation on November 25, 2003 pursuant to the series of transactions referred to above, 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 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 payables 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 June 30, 2004, Generation recorded no equity method income or loss as Sithe is consolidated in Generation’s results. For the three months ended June 30, 2003, Generation recorded $2 million of equity method losses. Generation recorded $2 million of equity method losses during the six months ended June 30, 2004 and no equity method income or losses for the six months ended June 30, 2003.

      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 June 30, 2004, Exelon has obtained $60 million of letters of credit in support of Sithe’s obligations not including a $50 million letter of credit which 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.

32

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Current assets			$	24
Noncurrent assets				232
	Total mark-to-market energy contract assets			256
Current liabilities				(16	)
Noncurrent liabilities				(140	)
	Total mark-to-market energy contract liabilities			(156	)
Total mark-to-market energy contract net assets			$	100

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 June 30, 2003		As Reported				AmerGen				Generating				Entries				Consolidated
Total operating revenue		$	3,721			$	159			$	130			$	(110	)		$	3,640
Operating income (loss)			800				21				(10	)			—				831
Income (loss) before cumulative effect of changes in accounting principles			372				38				(8	)			(20	)			398

						Acquisition				Sale of								Pro Forma
		Exelon				of 50% of				Boston				Eliminating				Exelon
Six Months Ended June 30, 2003		As Reported				AmerGen				Generating				Entries				Consolidated
Total operating revenue		$	7,795			$	307			$	183			$	(177	)		$	7,742
Operating income			1,557				59				8				—				1,608
Income before cumulative effect of changes in accounting principles			621				72				3				(37	)			653

      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.

33

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Exelon Condensed Consolidating Balance Sheet at June 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 payables and receivables between Generation and Sithe.

														Exelon
										Eliminating				Consolidated
June 30, 2004		Exelon				Sithe				Entries				(As Reported)
Assets
Current assets		$	4,317			$	370			$	(156	)		$	4,531
Assets held for sale(a)			11				9				—				20
Property, plant and equipment, net			19,954				274				—				20,228
Other noncurrent assets			16,589				770				(36	)			17,323
Total assets		$	40,871			$	1,423			$	(192	)		$	42,102
Liabilities and stockholders’ equity
Current liabilities		$	4,150			$	321			$	(156	)		$	4,315
Liabilities held for sale(a)			11				3				—				14
Long-term debt			13,100				819				—				13,919
Other long-term liabilities(b)			14,497				195				49				14,741
Stockholders’ equity(c)			9,113				85				(85	)			9,113
Total liabilities and stockholders’ equity		$	40,871			$	1,423			$	(192	)		$	42,102

---

(a)	Excludes assets and liabilities held for sale.

(b)	Includes minority interest of consolidated subsidiaries.

(c)	Includes preferred securities of subsidiaries.

34

---

 

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 June 30, 2003		As Reported				Acquired(a)				Disposed(b)				Entries				Consolidated
Total operating revenue		$	1,886			$	333			$	130			$	(154	)		$	1,935
Operating income (loss)			201				23				(10	)			—				234
Income (loss) before cumulative effect of changes in accounting principles			142				38				(8	)			(20	)			168

---

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

(b)	Includes the sale of Boston Generating.

																		Pro Forma
		Generation				Businesses				Businesses				Eliminating				Generation
Six Months Ended June 30, 2003		As Reported				Acquired(a)				Disposed(b)				Entries				Consolidated
Total operating revenue		$	3,765			$	811			$	183			$	(285	)		$	4,108
Operating income			295				45				8				—				332
Income before cumulative effect of changes in accounting principles			89				62				3				(37	)			111

---

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

(b)	Includes the sale of Boston Generating.

     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 acquisitions had actually occurred on January 1, 2003, nor of the results that might be obtained in the future.

35

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Generation Condensed Consolidating Balance Sheet at June 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 payables and receivables between Generation and Sithe.

																		Generation
										Exelon				Eliminating				Consolidated
June 30, 2004		Generation				Sithe				Energy				Entries				(As Reported)
Assets
Current assets(a)		$	2,515			$	370			$	68			$	(170	)		$	2,783
Assets held for sale			—				9				—				—				9
Property, plant and equipment, net			6,218				274				1				—				6,493
Other noncurrent assets			5,367				770				16				(36	)			6,117
Total assets		$	14,100			$	1,423			$	85			$	(206	)		$	15,402
Liabilities and members’ equity
Current liabilities(a)		$	2,496			$	321			$	66			$	(170	)		$	2,713
Liabilities held for sale			—				3				—				—				3
Long-term debt			1,650				819				—				—				2,469
Other long-term liabilities(b)			6,981				195				5				49				7,230
Members’ equity			2,973				85				14				(85	)			2,987
Total liabilities and members’ equity		$	14,100			$	1,423			$	85			$	(206	)		$	15,402

---

(a)	Excludes assets and liabilities held for sale.

(b)	Includes minority interest of consolidated subsidiaries.

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.” The tables below show the effect on net income

36

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 six months ended June 30, 2004 and 2003:

	Exelon

			Three Months
			Ended June 30,
			2004				2003
Net income — as reported			$	521			$	372
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes				(5	)			(5	)
Pro forma net income			$	516			$	367
Earnings per share:
	Basic — as reported		$	0.79			$	0.57
	Basic — pro forma		$	0.78			$	0.56
	Diluted — as reported		$	0.78			$	0.57
	Diluted — pro forma		$	0.77			$	0.56

			Six Months
			Ended June 30,
			2004				2003
Net income — as reported			$	933			$	733
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes				(10	)			(10	)
Pro forma net income			$	923			$	723
Earnings per share:
	Basic — as reported		$	1.41			$	1.13
	Basic — pro forma		$	1.40			$	1.11
	Diluted — as reported		$	1.40			$	1.12
	Diluted — pro forma		$	1.38			$	1.11

      The net income of ComEd, PECO and Generation for the three and six months ended June 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.

7.	Regulatory Issues (Exelon, ComEd and Generation)

	Exelon and ComEd

      PJM Integration. On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM Interconnection (PJM). The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of the transmission assets of ComEd and other new members, subject to a compliance filing and hearing on certain issues. 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 March 18, 2004, the FERC approved ComEd’s plan to complete its integration into PJM, subject to the North American Electric Reliability Council (NERC) approval of the

37

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PJM and Midwest ISO reliability plans to assure no adverse effects. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain other utilities harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004.

      Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. 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. ComEd began charging the new rates May 1, 2004. ComEd’s management believes an adequate reserve for any required refunds has been established in the event that the new rates are adjusted based on rehearing or settlement negotiations.

	Exelon and Generation

      Service Life Extension. Effective January 1, 2004, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities. 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) extensions of the existing NRC operating licenses. Generation has not applied for license extensions at the AmerGen 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.

38

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8.	Goodwill (Exelon and ComEd)

	Exelon

      As of June 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 June 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				(5	)			—				(5	)
Balances as of June 30, 2004			$	4,714			$	—			$	4,714

---

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

	ComEd

      As of June 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 June 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				(5	)
Balance as of June 30, 2004			$	4,714

---

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

39

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	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.

	Long-Term Debt

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

Interest

Company

Type

Rate

Maturity

Amount

PECO

First and Refunding Mortgage Bonds

5.90%

May 1, 2034

$

75

Total issuances

$

75

      Debt Retirements and Redemptions. During the six months ended June 30, 2004, the following debt was retired or redeemed:

Interest

Company

Type

Rate

Maturity

Amount

PECO

First and Refunding Mortgage Bonds

6.375%

August 15, 2005

$

75

ComEd

Note

7.375%

January 15, 2004

150

ComEd

Pollution Control Revenue Bonds

5.30%

January 15, 2004

26

ComEd

Sinking Fund Debentures

3.125%

April 1, 2004

1

ComEd

Sinking Fund Debentures

4.750%

June 1, 2004

1

Enterprises

Note

7.68%

June 30, 2023

11

Enterprises

Note

9.09%

January, 31, 2020

26

Total retirements and redemptions

$

290

      During the three and six months ended June 30, 2004, ComEd made payments of $86 million and $179 million, respectively, related to its obligation to the ComEd Transitional Funding Trust, and PECO made payments of $78 million and $166 million, respectively, related to its obligation to the PETT. Additionally, Exelon made payments on other long-term debt obligations of $22 million.

40

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Sithe Long-Term Debt. At June 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								Face
				Interest								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			$	122
		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												$	951
	Unamortized debt discount and premium, net												(99	)
	Long-term debt due within one year												(33	)
Total long-term debt												$	819

---

(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.

     Additionally, $3 million of Sithe’s long-term debt was classified as liabilities held for sale at June 30, 2004.

      Aggregate maturities of Sithe’s long-term debt relating to continuing operations are as follows:

2004		$	33
2005			34
2006			37
2007			40
2008			44
2009 and thereafter			763
Total minimum payments			951
Net debt discount to be amortized to interest expense			(99	)
Present value of minimum payments		$	852

41

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 1,650 positions for elimination through June 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.

      The following table presents, by segment, Exelon’s total salary continuance severance costs for the three and six months ended June 30, 2004. There were no significant salary continuance severance costs recorded during the three and six months ended June 30, 2003.

		Energy																Exelon
Salary continuance severance		Delivery				Generation				Enterprises				Corporate				Consolidated
Expense (income) recorded for three months ended June 30, 2004		$	(1	)		$	1			$	(1	)		$	4			$	3
Expense (income) recorded for six months ended June 30, 2004(a,b)			4				(5	)			—				5				4

---

(a)	In 2004, PECO recorded a charge of $4 million for new positions identified.

(b)	In 2004, Generation recorded a charge of $2 million for new positions identified and reversed $7 million to reduce accruals for individuals previously identified under The Exelon Way.

     The following table provides total salary continuance severance costs for ComEd, PECO and Generation for the three and six months ended June 30, 2004. There were no significant salary continuance severance costs recorded during the three and six months ended June 30, 2003.

Salary continuance severance		ComEd				PECO				Generation
Expense (income) recorded for three months ended June 30, 2004		$	—			$	(1	)		$	1
Expense (income) recorded for six months ended June 30, 2004(a,b)			—				4				(5	)

---

(a)	In 2004, PECO recorded a charge of $4 million for new positions identified.

(b)	In 2004, Generation recorded a charge of $2 million for new positions identified and reversed $7 million to reduce accruals for individuals previously identified under The Exelon Way.

42

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The following tables provide a roll forward of the salary continuance severance obligations from January 1, 2003 through June 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 (reductions)(a)(b)			4				—				4				(5	)
Payments			(42	)			(13	)			(4	)			(16	)
Other adjustments(c)			(3	)			—				—				—
Balance at June 30, 2004		$	98			$	42			$	14			$	22

---

(a)	In 2004, Generation recorded a charge of $2 million for new positions identified and reversed $7 million to reduce accruals for individuals previously identified under The Exelon Way.

(b)	In 2004, PECO recorded a charge of $4 million for new positions identified.

(c)	In 2004, Generation increased the reserve for liabilities acquired upon the transfer of the operations of Exelon Energy Company to Generation 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.

43

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      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 its 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.

      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.

44

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following tables present the components of Exelon’s net periodic benefit costs recognized for the three and six months ended June 30, 2004 and 2003, including the net periodic benefit costs of AmerGen’s pension and postretirement plans for 2004. The expected long-term rates of return on plan assets used to estimate 2004 pension and other postretirement benefit costs are 9.00% and 8.33%, respectively. 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 June 30,								Ended June 30,
			2004				2003				2004				2003
Service cost			$	33			$	27			$	20			$	17
Interest cost				134				130				44				41
Expected return on assets				(153	)			(146	)			(23	)			(19	)
Amortization of:
	Transition obligation (asset)			(1	)			(1	)			2				3
	Prior service cost			4				4				(19	)			(14	)
	Actuarial loss			15				5				15				12
Curtailment charge(a)				5				—				3				—
Special termination benefits charge(b)				—				—				8				—
Net periodic benefit cost			$	37			$	19			$	50			$	40

---

(a)	ComEd, PECO and Generation were allocated curtailment charges for pension and other postretirement benefits of $3 million, $2 million and $3 million, respectively.

(b)	ComEd, PECO and Generation were allocated special termination benefit charges related to other postretirement benefits of $3 million, $2 million and $2 million, respectively.

45

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

											Other
											Postretirement
			Pension Benefits								Benefits
			Six Months								Six Months
			Ended June 30,								Ended June 30,
			2004				2003				2004				2003
Service cost			$	66			$	54			$	40			$	34
Interest cost				268				260				89				83
Expected return on assets				(307	)			(292	)			(46	)			(38	)
Amortization of:
	Transition obligation (asset)			(2	)			(2	)			4				5
	Prior service cost			8				8				(38	)			(27	)
	Actuarial loss			30				11				30				24
Curtailment charge(a)				5				—				3				—
Special termination benefits charge(b)				—				—				8				—
Net periodic benefit cost			$	68			$	39			$	90			$	81

---

(a)	ComEd, PECO and Generation were allocated curtailment charges for pension and other postretirement benefits of $3 million, $2 million and $3 million, respectively.

(b)	ComEd, PECO and Generation were allocated special termination benefit charges related to other postretirement benefits of $3 million, $2 million and $2 million, respectively.

     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 six months ended June 30, 2004 and 2003:

		Three Months								Six Months
		Ended June 30,								Ended June 30,
Pension and Postretirement Benefit Costs		2004				2003				2004				2003
ComEd		$	23			$	23			$	47			$	46
PECO			8				13				16				28
Generation			30				24				59				48

      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 six months ended June 30, 2004 and 2003:

		Three Months								Six Months
		Ended June 30,								Ended June 30,
Savings plan matching contributions		2004				2003				2004				2003
Exelon		$	14			$	15			$	28			$	27
ComEd			4				5				8				9
PECO			1				2				3				4
Generation			6				6				13				12

46

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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								Six Months
			Ended June 30,								Ended June 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)			(6.5	)			—				(7.2	)			—
	Low income housing credit			(0.5	)			(0.6	)			(0.5	)			(0.7	)
	Plant basis differences			(0.4	)			(0.6	)			(0.4	)			(0.6	)
	Amortization of investment tax credit			(0.4	)			(0.4	)			(0.4	)			(0.5	)
	Tax exempt interest income			(0.3	)			(0.2	)			(0.4	)			(0.4	)
	State income taxes, net of Federal income tax benefit			2.7				3.4				2.7				3.6
	Nontaxable employee benefits			(0.3	)			—				(0.3	)			—
	Other, net			1.4				0.7				1.2				0.8
Effective income tax rate				30.7	%			37.3	%			29.7	%			37.2	%

---

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

	ComEd

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

			Three Months								Six Months
			Ended June 30,								Ended June 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			4.7				4.8				4.8				4.8
	Amortization of regulatory asset			0.5				0.5				0.5				0.5
	Amortization of investment tax credit			(0.2	)			(0.2	)			(0.2	)			(0.2	)
	Nontaxable employee benefits			(0.3	)			—				(0.2	)			—
	Other			(0.4	)			0.1				(0.2	)			(0.2	)
Effective income tax rate				39.3	%			40.2	%			39.7	%			39.9	%

47

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	PECO

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

			Three Months								Six Months
			Ended June 30,								Ended June 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			(1.4	)			(1.5	)			(1.2	)			(1.0	)
	State income taxes, net of Federal income tax benefit			(0.7	)			(0.2	)			0.3				0.9
	Amortization of investment tax credit			(0.4	)			(0.4	)			(0.4	)			(0.4	)
	Nontaxable employee benefits			(0.5	)			—				(0.2	)			—
	Other			1.3				4.2				(1.0	)			0.2
Effective income tax rate				33.3	%			37.1	%			32.5	%			34.7	%

	Generation

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

			Three Months								Six Months
			Ended June 30,								Ended June 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			3.1				3.4				3.5				8.0
	Tax exempt interest income			(0.9	)			(0.5	)			(1.3	)			(2.2	)
	Nontaxable employee benefits			(0.6	)			—				(0.5	)			—
	Amortization of investment tax credit			(0.4	)			(0.6	)			(0.6	)			(1.6	)
	Nuclear decommissioning trust income			1.3				1.7				2.0				4.2
	Other			0.1				0.1				—				0.4
Effective income tax rate				37.6	%			39.1	%			38.1	%			43.8	%

13.	Asset Retirement Obligations (Exelon and Generation)

      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 AmerGen plants, through regulated rates. The amounts recovered from

48

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

customers are deposited into trust accounts and invested for funding the future decommissioning costs of the nuclear generating stations.

      Exelon and Generation had $4,890 million and $4,721 million as of June 30, 2004 and December 31, 2003, respectively, recorded as nuclear decommissioning trust funds on Exelon’s and Generation’s Consolidated Balance Sheets which represent decommissioning assets in trust accounts. Generation anticipates that all trust fund assets will ultimately be used to decommission Generation’s nuclear plants.

      The following table presents a roll forward of the ARO reflected on the Exelon and Generation Consolidated Balance Sheets from January 1, 2003 to June 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
Accretion expense for the six months ended June 30, 2004			102				102
Additional liabilities incurred(b)			6				6
Expenditures to decommission retired plants			(5	)			(5	)
Asset retirement obligation at June 30, 2004		$	3,099			$	3,100

---

(a)	The ARO of Thermal was removed from the balance sheet upon its sale in the second quarter of 2004.

(b)	Additional liabilities incurred are primarily due to the consolidation of Sithe.

     Generation is currently evaluating changes in estimated future cash flows related to the decommissioning of its nuclear units that will impact the recorded amount of the ARO. This evaluation is expected to be completed by the end of 2004.

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.

49

---

 

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								Six Months
			Ended June 30,								Ended June 30,
			2004				2003				2004				2003
Income before cumulative effect of changes in accounting principles			$	521			$	372			$	901			$	621
Cumulative effect of changes in accounting principles				—				—				32				112
Net income			$	521			$	372			$	933			$	733
Average common shares outstanding — basic				661				650				660				649
Assumed exercise of stock options				6				5				6				4
Average common shares outstanding — diluted				667				655				666				653
Earnings per average common share — Basic:
	Income before cumulative effect of changes in accounting principles		$	0.79			$	0.57			$	1.36			$	0.96
	Cumulative effect of changes in accounting principles			—				—				0.05				0.17
	Net income		$	0.79			$	0.57			$	1.41			$	1.13
Earnings per average common share — Diluted:
	Income before cumulative effect of changes in accounting principles		$	0.78			$	0.57			$	1.35			$	0.95
	Cumulative effect of changes in accounting principles			—				—				0.05				0.17
	Net income		$	0.78			$	0.57			$	1.40			$	1.12

      The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 1 million and 10 million for the three months ended June 30, 2004 and 2003, respectively, and 1 million and 10 million for the six months ended June 30, 2004 and 2003, respectively.

	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 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

50

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

unless cancelled or reissued at the discretion of Exelon’s management. Treasury shares are recorded at cost. During the three and six months ended June 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 six months ended June 30, 2004:

																						Accumulated
																						Other
																						Comprehensive				Total
		Issued				Common				Treasury				Treasury				Retained				Income				Shareholders’
Dollars in millions, shares in thousands		Shares				Stock				Shares				Stock				Earnings				(Loss)				Equity
Balance, December 31, 2003			656,366			$	7,292				—			$	—			$	2,320			$	(1,109	)		$	8,503
Net income							—				—				—				933				—				933
Long-term incentive plan activity			5,956				166				—				—				—				—				166
Employee stock purchase plan issuances			155				5				—				—				—				—				5
Treasury stock purchases			—				—				2,327				(75	)			—				—				(75	)
Common stock dividends declared			—				—				—				—				(364	)			—				(364	)
Other comprehensive income (loss)			—				—				—				—				—				(142	)			(142	)
Balance, June 30, 2004			662,477			$	7,463				2,327			$	(75	)		$	2,889			$	(1,251	)		$	9,026

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

      For information regarding capital commitments, nuclear decommissioning and spent fuel storage 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 June 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 $46 million, transmission rights of $27 million and minimum fuel purchase commitments of $109 million.

	Commercial Commitments

      Exelon, ComEd, PECO and Generation’s commercial commitments as of June 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:

	•	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.

51

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	•	Generation acquired a $50 million letter of credit to support the contractual obligations of Sithe and its subsidiaries.
	•	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 June 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.

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

		Total environmental				Portion of total related
		investigation and				to MGP investigation
June 30, 2004		remediation reserve				and remediation(a)
Exelon		$	130			$	101
ComEd			66				61
PECO			50				40
Generation			14				—

---

(a)	Discounted.

		Total environmental				Portion of total related
		investigation and				to MGP investigation
December 31, 2003		remediation 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.

52

---

 

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. There is no set date by which the Court must decide if it will hear the remaining appeal. While ComEd cannot currently predict the ultimate outcome of this action, it does not believe that the action will have a material adverse effect on its results of operations or its cash flows.

	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 June 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. No date has been set for a new trial.

53

---

 

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. Generation cannot predict the ultimate outcome of the cases.

      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. 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, the lenders and 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. Under the global settlement, Generation agreed to pay approximately $31.1 million to Raytheon and approximately $1.4 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 has 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. Raytheon has also ceased all construction activities related to the Mystic 8 and 9 and Fore River generating facilities and assigned subcontracts to the project companies, and will cooperate with the transition of construction to a new contractor. In the event that the transfer of plant operations and power marketing activities are not completed by September 1, 2004, under the settlement documents among Exelon and the lenders, Generation will be reimbursed for the $32.5 million paid in connection with the settlement through a first claim against any payments otherwise payable to the lenders on account of their interests in the projects.

      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

54

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 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 $114 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 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 $21 million.

      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 tolling agreement associated with the Independence plant. 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. Additionally, 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. In February 2004, Dynegy announced an agreement to sell Illinois Power to a third party, which, upon closing of the transaction, would reduce 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 three months ended June 30, 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

55

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

	Jointly Owned Electric Utility Plant

      On January 28, 2004, the NRC issued a letter requesting PSE&G 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. PSE&G 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 need to be addressed. At an NRC public meeting on June 16, 2004, PSE&G 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.

      In June 2001, the NJDEP issued a renewed NPDES 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 FWPCA 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 PSE&G 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. PSE&G 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 require 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.

56

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

		June 30,				December 31,
ComEd		2004				2003
Regulatory Assets (Liabilities)
Nuclear decommissioning		$	(1,212	)		$	(1,183	)
Removal costs			(992	)			(973	)
Recoverable transition costs			109				131
Reacquired debt costs and interest-rate swap settlements			162				172
Deferred income taxes			(60	)			(61	)
Other			26				23
Total		$	(1,967	)		$	(1,891	)

		June 30,				December 31,
PECO		2004				2003
Regulatory Assets (Liabilities)
Competitive transition charge		$	4,129			$	4,303
Deferred income taxes			775				762
Non-pension postretirement benefits			55				58
Reacquired debt costs			45				49
MGP regulatory asset (see Note 15 — Commitments and Contingencies)			30				34
U.S. Department of Energy facility decommissioning			23				26
Nuclear decommissioning			(35	)			(12	)
Other			16				6
Long-term regulatory assets			5,038				5,226
Deferred energy costs (current asset)			25				81
Total		$	5,063			$	5,307

57

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following tables provide supplemental balance sheet information as of June 30, 2004 and December 31, 2003:

June 30, 2004			Exelon				ComEd				PECO				Generation
Property, plant and equipment:
	Accumulated depreciation		$	6,472			$	879			$	2,105			$	3,370
Accounts receivable:
	Allowance for uncollectible accounts			101				16				61				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.

58

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended June 30, 2004 and 2003

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

														Corporate and
		Energy												Intersegment
		Delivery				Generation				Enterprises				Eliminations				Consolidated
Total revenues(a):
2004		$	2,435			$	1,948			$	43			$	(876	)		$	3,550
2003			2,322				2,058	(b)			269	(b)			(928	)			3,721
Intersegment revenues:
2004		$	11			$	871			$	(4	)		$	(878	)		$	—
2003			19				896				14	(b)			(929	)			—
Income (loss) before income taxes and minority interest:
2004		$	485			$	266			$	51			$	(67	)		$	735
2003			481				234	(b)			(96	)(b)			(24	)			595
Income taxes:
2004		$	182			$	100			$	24			$	(80	)		$	226
2003			190				92	(b)			(35	)(b)			(25	)			222
Net income (loss):
2004		$	303			$	178			$	27			$	13			$	521
2003			291				142	(b)			(61	)(b)			—				372

---

(a)	$57 million and $51 million in utility taxes are included in the revenues and expenses for the three months ended June 30, 2004 and 2003, respectively, for ComEd. $50 million and $47 million in utility taxes are included in the revenues and expenses for the three months ended June 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 June 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 June 30, 2003, Exelon Energy Company reported the following:

Total revenues		$	174			Intersegment revenues		$	2
Income (loss) before income taxes		$	1			Income taxes		$	1
Net income (loss)		$	—

59

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Six Months Ended June 30, 2004 and 2003, June 30, 2004 and December 31, 2003

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

														Corporate and
		Energy												Intersegment
		Delivery				Generation				Enterprises				Eliminations				Consolidated
Total revenues(a):
2004		$	5,010			$	3,900			$	133			$	(1,771	)		$	7,272
2003			4,964				4,260	(b)			518	(b)			(1,947	)			7,795
Intersegment revenues:
2004		$	26			$	1,750			$	—			$	(1,776	)		$	—
2003			35				1,889				26	(b)			(1,950	)			—
Income (loss) before income taxes, minority interest and cumulative effect of changes in accounting principles:
2004		$	986			$	383			$	26			$	(129	)		$	1,266
2003			998				146	(b)			(109	)(b)			(41	)			994
Income taxes:
2004		$	367			$	146			$	15			$	(152	)		$	376
2003			382				65	(b)			(41	)(b)			(36	)			370
Cumulative effect of change in accounting principle:
2004		$	—			$	32			$	—			$	—			$	32
2003			5				108				(1)				—				112
Net income (loss):
2004		$	619			$	280			$	11			$	23			$	933
2003			621				187	(b)			(69	)(b)			(6	)			733
Total assets:
June 30, 2004		$	28,370			$	15,402	(c)		$	592			$	(2,262	)		$	42,102
December 31, 2003			28,369				14,753	(b)			727	(b)			(1,967	)			41,882

---

(a)	$119 million and $113 million in utility taxes are included in the revenues and expenses for the six months ended June 30, 2004 and 2003, respectively, for ComEd. $100 million and $98 million in utility taxes are included in the revenues and expenses for the six months ended June 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 six months ended June 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. Exelon Energy Company’s total assets as of December 31, 2003 were $104 million and for the six months ended June 30, 2003, Exelon Energy Company reported the following:

Total revenues		$	504			Intersegment revenues		$	9
Income (loss) before income taxes		$	(16	)		Income taxes		$	(6	)
Net income (loss)		$	(10	)

(c)	Includes $1,423 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.

60

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Prior periods were not restated in accordance with FIN No. 46-R.

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

			Three Months								Six Months Ended
			Ended June 30,								June 30,
			2004				2003				2004				2003
Interest expense to affiliates
	ComEd Transitional Funding Trust		$	21			$	—			$	45			$	—
	ComEd Financing II			4				—				7				—
	ComEd Financing III			3				—				6				—
Equity in losses from unconsolidated affiliates
	ComEd Funding LLC			(6	)			—				(9	)			—

			June 30,				December 31,
			2004				2003
Receivables from affiliates (current)
	ComEd Transitional Funding Trust		$	13			$	9
Investment in affiliates
	ComEd Funding, LLC			47				45
	ComEd Financing II			10				8
	ComEd Financing III			6				6
Receivable from affiliates (noncurrent)
	ComEd Transitional Funding Trust			10				9
Payables to affiliates (current)
	ComEd Financing II			6				6
	ComEd Financing III			4				4
Long-term debt to affiliates (including due within one year)
	ComEd Transitional Funding Trust			1,497				1,676
	ComEd Financing II			155				155
	ComEd Financing III			206				206

61

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

			Three Months								Six Months
			Ended June 30,								Ended June 30,
			2004				2003				2004				2003
Operating revenues from affiliates
	Generation(a)		$	5			$	15			$	16			$	26
	Enterprises(a)			1				1				1				3
Purchased power from affiliate
	PPA with Generation(b)			514				528				1,043				1,099
Operations & maintenance from affiliates
	BSC(c)			49				21				89				46
	Enterprises(d,e)			(4	)			3				1				6
Interest income from affiliates
	UII(f)			4				6				9				12
	Exelon intercompany money pool(j)			1				1				2				1
Capitalized costs
	BSC(c)			16				5				28				8
	Enterprises(e)			—				6				—				12
Cash dividends paid to parent				104				91				207				211

62

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			June 30,				December 31,
			2004				2003
Receivables from affiliates (current)
	UII(f)		$	9			$	3
	PECO(h)			—				6
	Exelon intercompany money pool(j)			198				405
	Other			—				5
Receivables from affiliates (noncurrent)
	UII(f)			1,071				1,071
	Generation(k)			1,212				1,183
	Other			7				8
Payables to affiliates (current)
	Generation decommissioning(g)			11				11
	Generation(a,b)			182				171
	BSC(c)			19				13
	Other			—				2
Payables to affiliates (noncurrent)
	Generation decommissioning(g)			22				22
	Other			5				6
Shareholders’ equity — receivable from parent(i)				188				250

---

(a)		ComEd provides electric, transmission and other ancillary services to Generation and Enterprises.
(b)		Effective January 1, 2001, ComEd entered into a full-requirements 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 has contracted with Services (an Enterprises company) to provide energy conservation services to ComEd customers. During the three months ended June 30, 2004, ComEd recorded a true-up of prior billings resulting in a credit balance.
(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.
(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.

63

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(j)		ComEd participates in Exelon’s intercompany money pool. ComEd earns interest on its investment in 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. 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								Six Months
			Ended June 30,								Ended June 30,
			2004				2003				2004				2003
Operating revenues from affiliate
	PETT(a)		$	3			$	—			$	5			$	—
Interest expense to affiliates
	PETT			59				—				119				—
	PECO Trust III			1				—				3				—
	PECO Trust IV			2				—				3				—

			June 30,				December 31,
			2004				2003
Investment in affiliates
	PETT		$	94			$	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			10				10
	PECO Energy Capital Corp			1				1
Long-term debt to affiliates (including due within one year)
	PETT			3,683				3,849
	PECO Trust III			81				81
	PECO Trust IV			103				103

---

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

64

---

 

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								Six Months Ended
			Ended June 30,								June 30,
			2004				2003				2004				2003
Operating revenues from affiliate
	Generation(a)		$	2			$	3			$	4			$	5
Purchased power from affiliate
	Generation(b)			349				324				699				681
Fuel from affiliate
	Generation(c)			7				—				7				—
Operating and maintenance from affiliates
	BSC(d)			28				10				51				22
	Enterprises(e)			—				1				—				3
Capitalized costs
	Enterprises(e)			—				7				—				13
	BSC(d)			5				2				9				3
Cash dividends paid to parent				90				76				180				165

			June 30,				December 31,
			2004				2003
Receivable from affiliate (current)
	Exelon intercompany money pool(i)		$	35			$	—
Receivable from affiliate (noncurrent)
	Generation decommissioning(f)			35				12
Payables to affiliates (current)
	Generation(b)			135				115
	BSC(d)			24				15
	ComEd(g)			—				6
	Other			—				3
Shareholder’s equity — receivable from parent(h)				1,553				1,623

---

(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.
(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.

65

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(f)		PECO has a long-term receivable from Generation related to a regulatory liability as a result of the adoption of SFAS No. 143.
(g)		In 2003, PECO received assistance from ComEd workers during Hurricane Isabel.
(h)		PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2004 through 2010.
(i)		PECO participates in Exelon’s intercompany money pool. PECO earns interest on its investment in the money pool at a market rate of interest.

	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								Six Months
			Ended June 30,								Ended June 30,
			2004				2003				2004				2003
Operating revenues from affiliates
	ComEd(a)		$	514			$	528			$	1,043			$	1,099
	PECO(a)			356				324				706				681
	Exelon Energy Company(b)			—				44				—				109
	BSC			1				—				1				—
Purchased power from affiliates
	AmerGen(c)			—				110				—				177
	ComEd(a)			3				13				12				20
	Exelon Energy Company(b)			—				2				—				9
Operating and maintenance from affiliates
	Sithe(d)			—				2				—				6
	ComEd(a)			2				2				4				6
	PECO(a)			2				3				4				6
	BSC(e)			65				35				126				70
Interest expense to affiliates
	Sithe(d)			—				3				—				6
	Exelon(f)			—				—				—				1
	Exelon intercompany money pool(f)			1				1				2				1
Services provided to affiliates
	AmerGen(c)			—				18				—				35
Cash distribution paid to member				109				45				109				45

66

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

			June 30,				December 31,
			2004				2003
Receivables from affiliates
	ComEd(a)		$	182			$	171
	ComEd decommissioning(g)			11				11
	PECO(a)			135				115
	BSC(e)			—				3
	Exelon Energy Company(b)			—				18
	Sithe(d)			—				3
	Other			6				8
Note receivable from affiliate
	Note receivable from Sithe(d)			—				92
	Other			1				—
Long-term receivable from affiliate
	ComEd decommissioning(g)			22				22
Payables to affiliates
	Exelon(f)			—				1
	BSC(e)			28				—
	Other			4				—
Payables to affiliates (non-current)
	ComEd decommissioning(h)			1,212				1,183
	PECO decommissioning(h)			35				12
Notes payable to affiliates
	Exelon(f)			—				115
	Exelon intercompany money pool(f)			198				301
	Sithe(d)			—				90

---

(a)		Effective January 1, 2001, Generation entered into full-requirements PPAs with ComEd and PECO. Generation purchases transmission 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.
(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 with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has

67

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.
(f)		Represents the outstanding balance of amounts 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 adoption of SFAS No. 143.

68

---

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Credit Facility (Exelon, ComEd, PECO and Generation)

      At June 30, 2004, 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.

	Synthetic Fuel-producing Facilities (Exelon)

      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. These facilities are not consolidated within Exelon’s financial statements because Exelon does not have a controlling financial interest in these 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 and will be amortized as the tax credits are earned. Private letter rulings have been received by the partnership that indicate these facilities qualify for tax credits under Section 29 of the Internal Revenue Code.

69

---

 

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 energy services business of Exelon Services, Inc. (Services), the remaining district cooling investments of Exelon Thermal Holdings, Inc. (Thermal), the remaining electrical contracting business of F & M Holdings, LLC, and other investments related to the communications, energy services and retail services industries. Effective January 1, 2004, the competitive retail sales business of Exelon Energy Company was transferred to Generation. See Note 3 of the Combined Notes to Consolidated Financial Statements for information regarding the disposition of businesses within the Enterprises segment during 2004.

      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 the business segments 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 and PECO 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. These costs are allocated to the business segments. Additionally, the results of Exelon’s corporate operations include costs for strategic long-term planning, certain governmental affairs, 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)

      Exelon, through Generation, has a 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

70

---

 

      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 and Generation.

New Accounting Pronouncements

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

71

---

 

EXELON CORPORATION

Executive Overview

      Financial Results. Exelon’s diluted earnings per average common share increased by 37% for the three months ended June 30, 2004 as compared to the same period in 2003, primarily as a result of decreased losses at Enterprises, an increase in net income at Generation and favorable tax effects from investments in synthetic fuel-producing facilities. Enterprises recorded a gain on the sale of Exelon Thermal Holdings, Inc. (Exelon Thermal) of $36 million (before income taxes and net of debt prepayment penalties), while Enterprises’ 2003 income reflected a goodwill impairment charge of $47 million (before income taxes) and investment-related impairment charges of $35 million (before income taxes). The increase in Generation’s net income reflects an $85 million gain (before income taxes) on the sale of Boston Generating, LLC (Boston Generating) during the second quarter of 2004. Exelon’s investments in synthetic fuel-producing facilities provided a tax benefit of $48 million and increased Exelon’s net income for the three months ended June 30, 2004 by $15 million.

      Exelon’s diluted earnings per average common share increased by 25% for the six months ended June 30, 2004 as compared to the same period in 2003, primarily as a result of decreased losses at Enterprises, an increase in net income at Generation and favorable tax effects from investments in synthetic fuel-producing facilities. Enterprises results were affected by the 2004 gain recorded on the sale of Thermal and the 2003 goodwill and investment impairment charges discussed above. The increase in Generation’s net income reflects a 2003 impairment charge of $200 million (before income taxes) related to Generation’s investment in Sithe and an $85 million gain (before income taxes) on the sale of Boston Generating during the second quarter of 2004. 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 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 half 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 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.
	•	Exelon continued to execute its divestiture strategy for Enterprises by selling five units of Exelon Services, Inc. (Services) during the six months ended June 30, 2004 for total expected proceeds of $34 million subject to post-closing adjustments, and 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 the Chicago business of Exelon Thermal during the second quarter of 2004 for net cash proceeds of $134 million and expects to close on the sale of the Aladdin thermal facility during the second half of 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 June 30, 2004, Enterprises had total assets and liabilities of $592 million and $200 million, respectively.

72

---

 

      Financing Activities. Exelon made payments of approximately $345 million for the purpose of retiring PECO and ComEd transition trust long-term debt and repaid approximately $237 million of other net long-term debt during the six months ended June 30, 2004. Exelon met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions. In January 2004, Exelon announced a 10% increase in its quarterly dividend on its common stock and approved a 2-for-1 split of its common stock. The distribution date was May 5, 2004. The share and per-share amounts included in this Form 10-Q have been adjusted for all periods presented to reflect the stock split. In the second quarter of 2004, Exelon’s Board of Directors approved a discretionary share repurchase program. Exelon purchased common stock, held as treasury shares as of June 30, 2004, totaling $75 million during the second quarter of 2004. Exelon also replaced its $750 million 364-day unsecured revolving credit agreement with a $1 billion five-year facility and reduced its $750 million three-year facility to $500 million in a transaction that closed on July 16, 2004.

      Regulatory Developments. 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, particularly after ComEd’s regulatory transition period ends in 2006; however, changes in market dynamics could affect the ultimate financial impact on Exelon.

      ComEd currently earns approximately $66 million annually from through and out (T&O) rates for energy flowing across ComEd’s transmission system. 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 and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’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 93.3% capacity factor for the six months ended June 30, 2004 compared to 94.2% in the same period of 2003 primarily as a result of increased planned outage days.

      Outlook for the Remainder of 2004 and Beyond. Exelon’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 — Exelon — Executive Summary” in the 2003 Form 10-K.

73

---

 

Results of Operations — Exelon Corporation

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

		2004				2003				Variance				% Change
Operating revenues		$	3,550			$	3,721			$	(171	)			(4.6	)%
Purchased power and fuel expense			1,211				1,387				(176	)			(12.7	)%
Operating and maintenance expense			1,056				1,100				(44	)			(4.0	)%
Operating income			783				800				(17	)			(2.1	)%
Other income and deductions			(48	)			(205	)			157				(76.6	)%
Income before income taxes and minority interest			735				595				140				23.5	%
Net income			521				372				149				40.1	%
Diluted earnings per share			0.78				0.57				0.21				36.8	%

      Operating Revenues. Operating revenues decreased for the three months ended June 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 the businesses of InfraSource, Inc. (InfraSource) during the third quarter of 2003, decreased competitive transition charge (CTC) collections at ComEd and 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 adoption of EITF 03-11 during 2004 changed the presentation of certain power transactions and decreased operating revenues by $239 million for the three months ended June 30, 2004 but had no effect on net income. The decreases in operating revenues were partially offset by higher delivery volume and favorable weather conditions at Energy Delivery and 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. 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 June 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 $239 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. Purchased power represented 23% of Generation’s total supply for the three months ended June 30, 2004 compared to 36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.

      Operating and Maintenance Expense. Operating and maintenance expense decreased for the three months ended June 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 the businesses of InfraSource during the third quarter of 2003 and a goodwill impairment charge recorded during 2003, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen, the consolidation of Sithe and increased costs at Boston Generating. Investments made by Exelon in the fourth quarter of 2003 in synthetic fuel-producing facilities increased operating and maintenance expense by $24 million. See further discussion of operating and maintenance expenses by segment below.

      Operating Income. The change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily the result of increased depreciation expense due to additional plant placed in service after the second quarter of 2003 and increased amortization expense due to investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities. Taxes other than income were higher in 2004 as compared to 2003, primarily at Energy Delivery, as a result of a refund of Illinois Electricity Distribution taxes at ComEd and the reversal of a use tax accrual resulting from an audit settlement at PECO, both in 2003.

74

---

 

      Other Income and Deductions. Other income and deductions changed primarily due to 2004 gains on the sales of Boston Generating and Exelon Thermal and 2003 investment impairments of $35 million recorded by Enterprises. Equity in earnings of unconsolidated affiliates decreased by $46 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. Interest expense and distributions on preferred securities of subsidiaries collectively increased $17 million, primarily due to increased interest expense at Generation.

      Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the three months ended June 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.

	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 June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

	Net Income (Loss) by Business Segment

		Three Months
		Ended June 30,
		2004				2003				Variance				% Change
Energy Delivery		$	303			$	291			$	12				4.1	%
Generation			178				142				36				25.4%
Enterprises			27				(61	)			88				n.m.
Corporate			13				—				13				n.m.
Total		$	521			$	372			$	149				40.1	%

---

n.m. — not meaningful

     Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The information for the three months ended June 30, 2003 related to the Enterprises and Generation segments discussed below has not 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 June 30, 2003 were as follows:

Total revenues		$	174
Intersegment revenues			2
Income before income taxes			1
Income taxes			1
Net income (loss)			—

75

---

 

	Results of Operations — Energy Delivery

		Three Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	2,435			$	2,322			$	113				4.9	%
Purchased power and fuel expense			1,059				986				73				7.4	%
Operating and maintenance expense			355				342				13				3.8	%
Depreciation and amortization expense			228				213				15				7.0	%
Operating income			661				666				(5	)			(0.8	)%
Interest expense			172				189				(17	)			(9.0	)%
Net income			303				291				12				4.1	%

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

										Total
		Electric				Gas				Variance
Volume		$	107			$	4			$	111
ComEd’s integration into PJM			43				—				43
Weather			43				(14	)			29
Rate changes and mix			(11	)			13				2
Customer choice			(67	)			—				(67	)
Other effects			(11	)			6				(5	)
Increase (decrease) in operating revenues		$	104			$	9			$	113

      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 commercial and industrial customers for ComEd and across all customer classes for PECO.

      ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. The increases relate 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.

      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 positively affected by favorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 68% and 66% higher, respectively. Heating degree-days in the ComEd and PECO service territories were 18% lower and 32% lower, respectively.

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

      Rate Changes and Mix. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. 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

76

---

 

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

      Electric revenues increased $17 million at PECO as a result of $12 million of favorable rate mix due to changes in monthly usage patterns in all customer classes and $5 million 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, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005.

      Energy Delivery’s gas revenues reflect increases in rates through PUC approved changes to the purchased gas adjustment clause that became effective June 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for the three months ended June 30, 2004 was 30% 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 has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.

      Customer Choice. For the three months ended June 30, 2004 and 2003, 29% and 25%, respectively, of energy delivered to Energy Delivery’s retail customers was provided by alternative electric suppliers (AES) or under the ComEd PPO. The decrease in electric retail revenues attributable to customer choice included a decrease in revenues of $51 million from customers in Illinois electing to purchase energy from an AES or under ComEd’s PPO and a decrease in revenues of $16 million from customers in Pennsylvania being assigned to or selecting an AES.

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

										Total
		Electric				Gas				Variance
Volume		$	44			$	3			$	47
ComEd’s integration into PJM			43				—				43
Prices			13				13				26
Weather			16				(10	)			6
Customer choice			(56	)			—				(56	)
Other			(3	)			10				7
Increase in purchased power and fuel expense		$	57			$	16			$	73

      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 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 increased customer growth and usage per customer across all customer classes.

77

---

 

      ComEd’s Integration into PJM. Energy Delivery’s operating revenues and purchased power expense each increased by $43 million in the three months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.

      Prices. Energy Delivery’s electric purchased power increased primarily due to an increase at PECO as a result of higher wholesale market prices associated with certain large commercial and industrial customers whose billing rates are tied to wholesale market prices for energy. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

      Weather. Energy Delivery’s purchased power and fuel expense increased due to the effect of favorable 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 ComEd’s PPO and PECO’s residential and small commercial and industrial customers selecting or being assigned to purchase energy from an AES.

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

		Variance
Higher corporate allocations(a)		$	29
Severance, pension and postretirement benefit costs associated with The Exelon Way			12
Tax consultant fees(b)			5
Employee fringe benefits(c)			(15	)
Contractors			(8	)
Environmental matters			(4	)
Other			(6	)
Increase in operating and maintenance expense		$	13

---

(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sale of certain Enterprises businesses.
(b)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 of the Combined Notes to Consolidated Financial Statements for more information).
(c)		During the second quarter of 2004, ComEd and PECO adopted the provisions of 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). Employee fringe benefits include a $2 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information related to employee fringe benefits.

     Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to increased competitive transition charge amortization of $7 million at PECO and increased depreciation of $5 million due to capital additions across Energy Delivery.

      Operating Income. The change in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was the result of increased taxes other than income. This increase was primarily attributable to $12 million related to the reversal of a PECO use tax accrual resulting from an audit settlement in 2003 and a 2003 ComEd refund of $5 million for Illinois Electricity Distribution Taxes.

      Interest Expense. The reduction in interest expense was primarily due to scheduled principal payments.

78

---

 

	Energy Delivery Operating Statistics and Revenue Detail

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

			Three Months
			Ended June 30,
Retail Deliveries — (in gigawatthours (GWhs))(a)			2004				2003				Variance				% Change
Full service(b)
Residential				8,065				7,437				628				8.4	%
Small commercial & industrial				6,477				6,646				(169	)			(2.5	)%
Large commercial & industrial				5,129				5,378				(249	)			(4.6	)%
Public authorities & electric railroads				1,424				1,555				(131	)			(8.4	)%
	Total full service			21,095				21,016				79				0.4	%
PPO (ComEd only)
Small commercial & industrial				870				869				1				0.1	%
Large commercial & industrial				877				1,318				(441	)			(33.5	)%
Public authorities & electric railroads				577				531				46				8.7	%
				2,324				2,718				(394	)			(14.5	)%
Delivery only(c)
Residential				488				186				302				162.4	%
Small commercial & industrial				2,194				1,580				614				38.9	%
Large commercial & industrial				3,280				2,320				960				41.4	%
Public authorities & electric railroads				406				247				159				64.4	%
				6,368				4,333				2,035				47.0	%
	Total PPO and delivery only			8,692				7,051				1,641				23.3	%
Total retail deliveries				29,787				28,067				1,720				6.1	%

---

(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.

79

---

 

			Three Months
			Ended June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	819			$	769			$	50				6.5	%
Small commercial & industrial				593				585				8				1.4	%
Large commercial & industrial				352				351				1				0.3	%
Public authorities & electric railroads				94				102				(8	)			(7.8	)%
	Total full service			1,858				1,807				51				2.8	%
PPO (ComEd only)(b)
Small commercial & industrial				60				59				1				1.7	%
Large commercial & industrial				51				72				(21	)			(29.2	)%
Public authorities & electric railroads				31				28				3				10.7	%
				142				159				(17	)			(10.7	)%
Delivery only(c)
Residential				38				14				24				171.4	%
Small commercial & industrial				58				49				9				18.4	%
Large commercial & industrial				48				48				—				—
Public authorities & electric railroads				9				8				1				12.5	%
				153				119				34				28.6	%
	Total PPO and delivery only			295				278				17				6.1	%
Total electric retail revenues				2,153				2,085				68				3.3	%
	Wholesale and miscellaneous revenue(d)			163				127				36				28.3	%
Total electric revenue			$	2,316			$	2,212			$	104				4.7	%

---

(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 ComEd’s 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.

80

---

 

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

		Three Months
		Ended June 30,
Deliveries to customers (in million cubic feet (mmcf))		2004				2003				Variance				% Change
Retail sales			8,162				9,222				(1,060	)			(11.5	)%
Transportation			6,410				5,779				631				10.9	%
Total			14,572				15,001				(429	)			(2.9	)%

		Three Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Retail sales		$	102			$	99			$	3				3.0	%
Transportation			4				4				—				—
Resales and other			13				7				6				85.7	%
Total		$	119			$	110			$	9				8.2	%

	Results of Operations — Generation

		Three Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	1,948			$	1,886			$	62				3.3	%
Purchased power and fuel expense			1,025				1,148				(123	)			(10.7	)%
Operating and maintenance expense			623				451				172				38.1	%
Operating income			183				201				(18	)			(9.0	)%
Income before income taxes and minority interest			266				233				33				14.2	%
Net income			178				142				36				25.4	%

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

		Variance
Retail gas revenue		$	84
Wholesale and retail electric sales			(39	)
Electric revenue from affiliates			(31	)
Other			48
Increase in operating revenues		$	62

      Retail Gas Revenue. Retail gas revenue increased $84 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

81

---

 

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

		Variance
Effects of the adoption of EITF 03-11(a)		$	(238	)
Sale of Boston Generating			(43	)
Exelon Energy Company and AmerGen operations			104
Other operations			138
Decrease in wholesale and retail electric sales		$	(39	)

---

(a)		Does not include $1 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. 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 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased wholesale and retail electric sales of approximately $104 million compared to the same period in the prior year.

      The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

      Electric Revenue from Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004 as a result of which 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 June 30, 2003 was $44 million.

      The decrease in revenue from sales to affiliates was partially offset by $15 million in higher sales to Energy Delivery. The higher sales to Energy Delivery were primarily due to overall increased usage per customer and favorable weather conditions.

      Other. Certain other revenues increased for the three months ended June 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. The changes in Generation’s purchased power and fuel expense for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Effects of the adoption of EITF 03-11		$	(239	)
Boston Generating			(33	)
Midwest Generation			(25	)
AmerGen and Exelon Energy Company			(11	)
Volume			92
Sithe Energies, Inc.			62
Price			49
Mark-to-market adjustments on hedging activity			11
Other			(29	)
Decrease in purchased power and fuel expense		$	(123	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $238 million and fuel expense of $1 million.

82

---

 

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating.

      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, purchased power decreased $97 million. 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 $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.

      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 is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation above for further information).

      Sithe Energies, Inc. 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.

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

      Hedging Activity. Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.

      Other. Other decreases in purchased power and fuel expense were primarily due to $21 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 and $10 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

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

		Variance
AmerGen and Exelon Energy Company		$	87
Sithe Energies, Inc.			22
Decommissioning accretion costs(a)			18
Boston Generating			13
Pension, payroll and benefit costs, primarily associated with The Exelon Way			(14	)
Other			46
Increase in operating and maintenance expense		$	172

---

(a)		Includes $10 million due to AmerGen asset retirement obligation accretion.

     The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated financial results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to the Mystic 8 and 9 and Fore River facilities commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting

83

---

 

      Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended June 30, 2004 as compared to the same period in 2003 includes the impact of 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 as the assets were classified as held for sale during the period.

      Effective Income Tax Rate. The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% 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. This impairment charge was taxed at a rate different than the overall generation effective income tax rate. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

	Generation Operating Statistics

      Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:

		Three Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Sales to affiliates(a)		$	846			$	877			$	(31	)			(3.5	)%
Wholesale and retail electric sales(b)			858				897				(39	)			(4.3	)%
Total energy sales revenue			1,704				1,774				(70	)			(3.9	)%
Retail gas sales			84				—				84				n.m.
Trading portfolio			(2	)			(1	)			(1	)			100.0	%
Other revenue(c)			162				113				49				43.4	%
Total revenue		$	1,948			$	1,886			$	62				3.3	%

---

(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 June 30,
Sales (in GWhs)		2004(c)				2003				Variance				% Change
Sales to affiliates(a)			26,133				26,869				(736	)			(2.7	)%
Wholesale and retail electric sales(b)			24,976				27,449				(2,473	)			(9.0	)%
Total sales			51,109				54,318				(3,209	)			(5.9	)%

---

(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 6,185 GWhs, which were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11.

84

---

 

		Three Months
		Ended June 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			34,254				29,619				4,635				15.6	%
Purchases — non-trading portfolio(b)			11,904				19,344				(7,440	)			(38.5	)%
Fossil and hydroelectric generation			4,951				5,355				(404	)			(7.5	)%
Total supply			51,109				54,318				(3,209	)			(5.9	)%

---

(a)		Excludes AmerGen in 2003. AmerGen generated 5,122 GWhs during the three months ended June 30, 2004.
(b)		Sales in 2004 do not include 6,185 GWhs that 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 3,731 GWhs in 2003.

     Trading volumes of 5,324 GWhs and 7,919 GWhs for the three months ended June 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 supply mix changed primarily as a result of the sale of Boston Generating in May 2004.

      Generation’s average margin and other operating data for the three months ended June 30, 2004 and 2003 were as follows:

			Three Months
			Ended June 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates(a)		$	32.37			$	32.64				(0.8	)%
	Market and retail electric sales(b)			34.35				32.68				5.1	%
	Total — excluding the trading portfolio			33.34				32.66				2.1	%
Average supply cost(c) — excluding the trading portfolio			$	20.06			$	21.13				(5.1	)%
Average margin — excluding the trading portfolio			$	13.28			$	11.53				15.2	%

---

(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 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.

     Generation’s average margin, excluding the trading portfolio, increased primarily due to decreased average supply cost as a result of forward hedging of fuel at lower costs during the three months ended June 30, 2004 as compared to the same period in the prior year. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and the affect of acquiring the remaining 50% of AmerGen in 2003. The increase in nuclear generation during the quarter, which is

85

---

 

		Three Months
		Ended June 30,
		2004				2003
Nuclear fleet capacity factor(a)			96.1	%			94.0	%
Nuclear fleet production cost per MWh(a)		$	10.88			$	12.08
Average purchased power cost for wholesale operations per MWh(b)		$	47.13			$	41.36

---

(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 and lower nuclear production costs were primarily due to nine fewer planned refueling outage days, resulting in a $14 million decrease in planned outage costs for the three months ended June 30, 2004 as compared to the same period in 2003. There was one planned refueling outage that began in late March 2004 and was completed during the three months ended June 30, 2004, while there was one refueling outage that began and was completed during the three months ended June 30, 2003. The three months ended June 30, 2004 included seven unplanned outages compared to nine unplanned outages during the same period in 2003.

      In the three months ended June 30, 2004 as compared to the three months ended June 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.

	Results of Operations — Enterprises

		Three Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	43			$	443			$	(400	)			(90.3	)%
Purchased power and fuel expense			—				166				(166	)			(100.0	)%
Operating and maintenance expense			65				322				(257	)			(79.8	)%
Depreciation and amortization expense			—				10				(10	)			(100.0	)%
Operating income (loss)			(23	)			(57	)			34				(59.6	)%
Other income and deductions			74				(38	)			112				n.m.
Loss before income taxes			51				(95	)			146				n.m.
Net income (loss)			27				(61	)			88				n.m.

      Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ results for the three months ended June 30, 2004 compared to the three months ended June 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 Energy Company. Effective January 1, 2004, the operations and assets of Enterprises’ competitive retail sales business, Exelon Energy Company, were transferred to Generation. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of this transfer.

      Exelon Services, Inc. During the three months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the three months ended June 30, 2004 related to the disposition of these Services businesses were $16 million and $12 million,

86

---

 

      In addition, during the three months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of operations.

      Exelon Thermal Holdings Inc. On June 30, 2004, Enterprises sold its Chicago business of Exelon 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.

      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.

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

		Variance
Transfer of Exelon Energy Company to Generation		$	(174	)
Sale of InfraSource businesses			(145	)
Services(a)			(61	)
F&M Holdings, LLC(b)			(28	)
Other			8
Decrease in operating revenues		$	(400	)

---

(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 the reduction of new business as a result of wind-down efforts.

     Purchased Power and Fuel Expense. Purchased power and fuel expense decreased as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004.

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

		Variance
Sale of InfraSource businesses		$	(135	)
Services(a)			(52	)
Goodwill impairment charge(b)			(47	)
F & M Holdings, LLC(c)			(22	)
Other			(1	)
Decrease in operating and maintenance expense		$	(257	)

---

(a)		Primarily due to the sale of certain businesses.
(b)		Enterprises recorded a goodwill impairment charge of $47 million during the second quarter of 2003 related to the goodwill recorded within the InfraSource reporting unit.

87

---

 

(c)		For the remaining businesses of F & M Holdings, LLC, operating and maintenance expense decreased $29 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $7 million due to margin deterioration on various construction projects.

     Depreciation and Amortization. Depreciation and amortization expense decreased primarily as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003 and property, plant and equipment classified as held for sale.

      Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sales of Exelon Thermal, the Services businesses and Enterprises’ investment in PECO Telcove of an aggregate of $66 million (before income taxes and 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-related and communications investments of $35 million.

      Effective Income Tax Rate. The effective income tax rate was 47% for the three months ended June 30, 2004 compared to 36% for the same period in 2003. The increase in the effective tax rate was primarily attributable to state tax impact on the Thermal divestiture and tax adjustments resulting from various income tax related items.

	Results of Operations — Exelon Corporation

	Six Months Ended June 30, 2004 Compared To Six Months Ended June 30, 2003

		2004				2003				Variance				% Change
Operating revenues		$	7,272			$	7,795			$	(523	)			(6.7	)%
Purchased power and fuel expense			2,608				3,119				(511	)			(16.4	)%
Operating and maintenance expense			2,165				2,212				(47	)			(2.1	)%
Operating income			1,505				1,557				(52	)			(3.3	)%
Other income and deductions			(239	)			(563	)			324				(57.5	)%
Income before income taxes, minority interest and cumulative effect of changes in accounting principles			1,266				994				272				27.4	%
Income before cumulative effect of changes in accounting principles			901				621				280				45.1	%
Cumulative effect of changes in accounting principles			32				112				(80	)			(71.4	)%
Net income			933				733				200				27.3	%
Diluted earnings per share			1.40				1.12				0.28				25.0	%

      Operating Revenues. Operating revenues decreased for the six months ended June 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 the businesses of InfraSource during the third quarter of 2003 and 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 $452 million. The adoption of EITF 03-11 had no impact on net income. See further discussion of operating revenues by segment below.

      Purchased Power and Fuel Expense. Purchased power and fuel expense decreased during the six months ended June 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 $452 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 consolidation of Sithe. Purchased power represented 23% of Generation’s total supply for the six months ended June 30, 2004 compared to 36% for the same period in 2003. See further discussion of purchased power and fuel expense by segment below.

88

---

 

      Operating and Maintenance Expense. Operating and maintenance expense decreased slightly for the six months ended June 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 the businesses of InfraSource during the third quarter of 2003 and decreased expenses at Energy Delivery due to a 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 and generating assets placed in service after the first quarter of 2003. Operating and maintenance expense increased $48 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.

      Operating Income. The slight decrease in operating income, exclusive of the changes in operating revenues, purchased power and fuel expense and operating and maintenance expense discussed above, was primarily due to an increase of $67 million in depreciation expense and increased taxes other than income at Energy Delivery. The increase in depreciation and amortization expense was primarily related to assets placed in service after the second quarter of 2003 and investments made in the fourth quarter of 2003 in synthetic fuel-producing facilities.

      Other Income and Deductions. Other income and deductions changed primarily due to an impairment charge of $200 million (before income taxes) recorded during the first quarter of 2003 related to Generation’s investment in Sithe, an $85 million gain (before income taxes) on the sale of Boston Generating and a $36 million gain on the sale of Exelon Thermal (before income taxes and net of debt prepayment penalties). Equity in earnings of unconsolidated affiliates decreased by $88 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. Interest expense and distributions on preferred securities of subsidiaries collectively increased $6 million, primarily due to increased interest expense at Generation, partially offset by lower outstanding debt and refinancings at lower rates at Energy Delivery.

      Effective Income Tax Rate. Exelon’s effective income tax rate decreased from 37% for the six months ended June 30, 2003 to 30% 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 six months ended June 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 net income for the six months ended June 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 six months ended June 30, 2004 and 2003 set forth below reflect intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

89

---

 

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

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Energy Delivery		$	619			$	616			$	3				0.5	%
Generation			248				89				159				178.7	%
Enterprises			11				(78	)			89				n.m.
Corporate			23				(6	)			29				n.m.
Total		$	901			$	621			$	280				45.1	%

---

n.m. — not meaningful

	Net Income (Loss) by Business Segment

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Energy Delivery		$	619			$	621			$	(2	)			(0.3	)%
Generation			280				197				83				42.1	%
Enterprises			11				(79	)			90				n.m.
Corporate			23				(6	)			29				n.m.
Total		$	933			$	733			$	200				27.3	%

---

n.m. — not meaningful

     Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, became part of Generation. The information for the six months ended June 30, 2003 related to the Enterprises and Generation segments discussed below has not 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 six months ended June 30, 2003 were as follows:

Total revenues		$	504
Intersegment revenues			9
Loss before income taxes			(16	)
Income tax benefit			(6	)
Net loss			(10	)

90

---

 

	Results of Operations — Energy Delivery

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	5,010			$	4,964			$	46				0.9	%
Purchased power and fuel expense			2,239				2,175				64				2.9	%
Operating and maintenance expense			704				744				(40	)			(5.4	)%
Depreciation and amortization expense			455				427				28				6.6	%
Operating income			1,343				1,360				(17	)			(1.3	)%
Interest expense			355				383				(28	)			(7.3	)%
Income before income taxes and cumulative effect of a change in accounting principle			986				998				(12	)			(1.2	)%
Income before cumulative effect of a change in accounting principle			619				616				3				0.5	%
Net income			619				621				(2	)			(0.3	)%

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

										Total
		Electric				Gas				Variance
Volume		$	158			$	(4	)		$	154
ComEd’s integration in PJM			43				—				43
Rate changes and mix			(68	)			82				14
Customer choice			(149	)			—				(149	)
Weather			13				(19	)			(6	)
Other effects			(16	)			6				(10	)
(Decrease) increase in operating revenues		$	(19	)		$	65			$	46

      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 commercial and industrial customers for ComEd and across all customer classes for PECO.

      ComEd’s Integration into PJM. Energy Delivery’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.

      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 $120 million for the six months ended June 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 ComEd’s PPO by $47 million.

      Customer Choice. For the six months ended June 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 $107 million from customers in Illinois electing to purchase energy from an AES or ComEd’s PPO and a decrease in revenues of $42 million from customers in Pennsylvania being assigned to or selecting an AES.

      For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 million, respectively, of CTC revenue. As a result of increasing mitigation factors, changes in energy

91

---

 

      Electric revenues increased $2 million at PECO as a result of $9 million related to a scheduled phase-out of merger-related rate reductions, largely offset by a $7 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. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005

      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 six months ended June 30, 2004 was 39% higher than the rate for the same period in 2003.

      Weather. Energy Delivery’s electric revenues were affected by favorable weather conditions. Cooling degree-days in the ComEd and PECO service territories were 68% higher and 66% higher, respectively, for the six months ended June 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 six months ended June 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 six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Electric				Gas				Total Variance
Prices		$	—			$	82			$	82
Volume			81				(4	)			77
ComEd’s integration into PJM			43				—				43
Customer choice			(134	)			—				(134	)
Weather			5				(16	)			(11	)
Other			(6	)			13				7
(Decrease) increase in purchased power and fuel expense		$	(11	)		$	75			$	64

      Prices. Energy Delivery’s purchased power expense remained constant. 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 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 increased customer growth and usage per customer across all customer classes.

      ComEd’s Integration into PJM. Energy Delivery’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM. 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

92

---

 

      Weather. Energy Delivery’s purchased power and fuel expense were affected by unfavorable weather conditions.

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

		Variance
Charge recorded at ComEd in 2003(a)		$	(41	)
Decreased payroll expense due to fewer employees(b)			(21	)
Contractors			(9	)
Allowance for uncollectible accounts expense			(6	)
Environmental charges			(5	)
Employee fringe benefits(b, d)			(3	)
Higher corporate allocations(c)			42
Severance, pension and postretirement benefit costs associated with The Exelon Way			19
Tax Consultant fees(e)			5
Other			(21	)
Decrease in operating and maintenance expense		$	(40	)

---

(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)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sale of certain Enterprises businesses.
(d)		During the second quarter of 2004, ComEd and PECO 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)		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 $14 million at PECO and increased depreciation of $10 million due to capital additions across Energy Delivery.

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

93

---

 

	Energy Delivery Operating Statistics and Revenue Detail

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

			Six Months
			Ended June 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				17,821				17,438				383				2.2	%
Small commercial & industrial				13,294				14,053				(759	)			(5.4	)%
Large commercial & industrial				10,091				10,344				(253	)			(2.4	)%
Public authorities & electric railroads				2,893				3,224				(331	)			(10.3	)%
	Total full service			44,099				45,059				(960	)			(2.1	)%
PPO (ComEd only)
Small commercial & industrial				1,600				1,662				(62	)			(3.7	)%
Large commercial & industrial				1,624				2,750				(1,126	)			(40.9	)%
Public authorities & electric railroads				1,012				1,069				(57	)			(5.3	)%
				4,236				5,481				(1,245	)			(22.7	)%
Delivery only(b)
Residential				1,070				450				620				137.8	%
Small commercial & industrial				4,389				3,131				1,258				40.2	%
Large commercial & industrial				6,371				4,362				2,009				46.1	%
Public authorities & electric railroads				894				529				365				69.0	%
				12,724				8,472				4,252				50.2	%
	Total PPO and delivery only			16,960				13,953				3,007				21.6	%
Total retail deliveries				61,059				59,012				2,047				3.5	%

---

(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.

94

---

 

			Six Months Ended
			June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	1,691			$	1,673			$	18				1.1	%
Small commercial & industrial				1,143				1,177				(34	)			(2.9	)%
Large commercial & industrial				682				692				(10	)			(1.4	)%
Public authorities & electric railroads				188				207				(19	)			(9.2	)%
	Total full service			3,704				3,749				(45	)			(1.2	)%
PPO (ComEd only)(b)
Small commercial & industrial				108				109				(1	)			(0.9	)%
Large commercial & industrial				92				144				(52	)			(36.1	)%
Public authorities & electric railroads				53				55				(2	)			(3.6	)%
				253				308				(55	)			(17.9	)%
Delivery only(c)
Residential				80				31				49				158.1	%
Small commercial & industrial				110				99				11				11.1	%
Large commercial & industrial				93				103				(10	)			(9.7	)%
Public authorities & electric railroads				18				17				1				5.9	%
				301				250				51				20.4	%
	Total PPO and delivery only			554				558				(4	)			(0.7	)%
Total electric retail revenues				4,258				4,307				(49	)			(1.1	)%
	Wholesale and miscellaneous revenue(d)			288				258				30				11.6	%
Total electric revenue			$	4,546			$	4,565			$	(19	)			(0.4	)%

---

(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 ComEd’s 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:

		Six Months
		Ended June 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			37,965				40,685				(2,720	)			(6.7	)%
Transportation			13,542				13,942				(400	)			(2.9	)%
Total			51,507				54,627				(3,120	)			(5.7	)%

95

---

 

		Six Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Retail sales		$	431			$	372			$	59				15.9	%
Transportation			9				9				—				—
Resales and other			24				18				6				33.3	%
Total		$	464			$	399			$	65				16.3	%

	Results of Operations — Generation

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	3,900			$	3,765			$	135				3.6	%
Purchased power and fuel expense			2,129				2,348				(219	)			(9.3	)%
Operating and maintenance expense			1,273				943				330				35.0	%
Operating income			279				295				(16	)			(5.4	)%
Income before income taxes, minority interest and cumulative effect of changes in accounting principles			383				162				221				136.4	%
Income before cumulative effect of changes in accounting principles			248				89				159				178.7	%
Cumulative effect of changes in accounting principles			32				108				(76	)			(70.4	)%
Net income			280				197				83				42.1	%

      Operating Revenues. The changes in Generation’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Retail gas revenue		$	260
Electric sales to affiliates			(136	)
Wholesale and retail electric sales			(12	)
Other			23
Increase in operating revenues		$	135

      Retail Gas Revenue. Retail gas revenue increased as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

      Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company’s assets and operations 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 six months ended June 30, 2003 was $108 million.

      The decrease in revenue from affiliates included $40 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.

96

---

 

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

		Variance
Effects of the adoption of EITF 03-11(a)		$	(444	)
Boston Generating			74
Exelon Energy Company and AmerGen operations			182
Other operations			176
Decrease in wholesale and retail electric sales		$	(12	)

---

(a)		Does not include $8 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 other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

      Other. Certain other revenues increased for the six months ended June 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. The changes in Generation’s purchased power and fuel expense for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Effects of the adoption of EITF 03-11		$	(452	)
Midwest Generation			(48	)
Price			(47	)
Volume			129
AmerGen and Exelon Energy Company			101
Sithe Energies, Inc.			62
Boston Generating			75
Mark-to-market adjustments on hedging activity			19
Other			(58	)
Decrease in purchased power and fuel expense		$	(219	)

      Effects of the Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power expense of $444 and fuel expense of $8 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.

      Price. The decrease primarily reflects lower average fossil fuel costs of $47 million during the six months ended June 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).

      AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $160 million. In prior periods,

97

---

 

      Boston Generating. The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May of 2004. The Mystic 8 and 9 generating facilities began commercial operations at the end of the second quarter of 2003, and the Fore River generating facilities began commercial operations during the third quarter of 2003.

      Sithe Energies, Inc. 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.

      Hedging Activity. Mark-to-market losses on hedging activities were $18 million for the six months ended June 30, 2004 compared to gains of $1 million for the same period in 2003. Hedging activities in 2004 related to Boston Generating operations accounted for a gain of $4 million and hedging activities for other Generation operations in 2004 accounted for a loss of $22 million.

      Other. Other decreases in purchased power and fuel were primarily due to $46 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, offset by $16 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

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

		Variance
AmerGen and Exelon Energy Company(a)		$	197
Refueling outage costs			38
Boston Generating			33
Decommissioning accretion costs(b)			25
Sithe Energies, Inc.			22
Pension, payroll and benefit costs associated with The Exelon Way			(23	)
Other			38
Increase in operating and maintenance expense		$	330

---

(a)		Includes refueling outage expense of $24 million at AmerGen.
(b)		Includes $20 million due to AmerGen asset retirement obligation accretion.

     Depreciation and Amortization. The increase in depreciation and amortization expense for the six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to the impact of capital additions and the consolidation of Sithe Energies, AmerGen, and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities as the assets were classified as held for sale during the period.

      Effective Income Tax Rate. The effective income tax rate was 38% for the six months ended June 30, 2004 compared to 44% for the same period in 2003. The decrease was primarily attributable to the impairment charge recorded in 2003 related to Generation’s investment in Sithe that resulted in a pre-tax loss. The impairment charge was taxed at a rate different than the overall Generation effective tax rate. 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 six months ended June 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

98

---

 

	Generation Operating Statistics

      Generation’s sales and the supply of these sales, excluding the trading portfolio, were as follows:

		Six Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Sales to affiliates(a)		$	1,706			$	1,842			$	(136	)			(7.4	)%
Wholesale and retail electric sales(b)			1,742				1,754				(12	)			(0.7	)%
Total energy sales revenue			3,448				3,596				(148	)			(4.1	)%
Retail gas sales			260				—				260				n.m.
Trading portfolio			(2	)			(2	)			—				n.m.
Other revenue			194				171				23				13.5	%
Total revenue		$	3,900			$	3,765			$	135				3.6	%

---

(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

		Six Months Ended
		June 30,
Sales (in GWhs)		2004				2003				Variance				% Change
Sale to affiliates(a)			53,597				57,463				(3,866	)			(6.7	)%
Wholesale and retail electric sales(b)			48,959				51,264				(2,305	)			(4.5	)%
Total sales			102,556				108,727				(6,171	)			(5.7	)%

---

(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 11,638 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.

		Six Months Ended
		June 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			67,665				58,949				8,716				14.8	%
Purchases — non-trading portfolio(b)			23,595				39,373				(15,778	)			(40.1	)%
Fossil and hydroelectric generation			11,296				10,405				891				8.6	%
Total supply			102,556				108,727				(6,171	)			(5.7	)%

---

(a)		Excludes AmerGen in 2003. AmerGen generated 9,761 GWhs during the six months ended June 30, 2004.
(b)		Sales in 2004 do not include 11,638 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 PPAs with AmerGen, which represented 6,219 GWhs in 2003.

99

---

 

     Trading volumes of 10,437 GWhs and 17,446 GWhs for the six months ended June 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 supply mix changed as a result of increased fossil generation due to Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total account for an increase of 2,688 GWhs.

      Generation’s average margin and other operating data for the six months ended June 30, 2004 and 2003 were as follows:

			Six Months Ended
			June 30,
($/MWh)			2004				2003				% Change
Average revenue
	Energy Delivery and Exelon Energy Company(a)		$	31.83			$	32.06				(0.7	)%
	Market and retail electric sales(b)			35.58				34.22				4.0	%
	Total — excluding the trading portfolio			33.62				33.07				1.7	%
Average supply cost(c) — excluding the trading portfolio			$	20.77			$	21.60				(3.8	)%
Average margin — excluding the trading portfolio			$	12.85			$	11.47				12.0	%

---

(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 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.

     Generation’s average margin, excluding the trading portfolio, increased primarily due to decreased average supply cost as a result of forward hedging of fuel at lower costs than prior periods. Also, Generation experienced a decrease in purchased power due to reducing the capacity purchased from Midwest Generation and the impact of consolidating AmerGen in 2003. The increase in nuclear generation during the period, which is generally less expensive than purchased power, along with the effect of the adoption of EITF 03-11, contributed to the increase in average margin. The increase in nuclear generation is due primarily to the consolidation of AmerGen.

		Six Months
		Ended June 30,
		2004				2003
Nuclear fleet capacity factor(a)			93.3	%			94.2	%
Nuclear fleet production cost per MWh(a)		$	12.54			$	12.40
Average purchased power cost for wholesale operations per MWh(b)		$	45.81			$	41.68

---

(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 and increased nuclear production costs were primarily due to 55 additional planned refueling outage days, resulting in a $46 million increase in planned outage costs in the six months ended June 30, 2004 as compared to the same period in 2003. There were five planned outages during the six months ended June 30, 2004, compared to three planned outages during the same period in 2003. The six months ended June 30, 2004 included twelve unplanned outages compared to eleven unplanned outages during the same period in 2003. 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.

100

---

 

	Results of Operations — Enterprises

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Operating revenues		$	133			$	1,022			$	(889	)			(87.0	)%
Purchased power and fuel expense			—				505				(505	)			(100.0	)%
Operating and maintenance expense			170				575				(405	)			(70.4	)%
Depreciation and amortization expense			—				20				(20	)			(100.0	)%
Operating income (loss)			(42	)			(84	)			42				(50.0	)%
Other income and deductions			68				(41	)			109				n.m.
Loss before income taxes and cumulative effect of change in accounting principle			26				(125	)			151				n.m.
Loss before cumulative effect of change in accounting principle			11				(78	)			89				n.m.
Net income (loss)			11				(79	)			90				n.m.

      Divestiture of Businesses and Investments. Exelon is continuing to execute its divestiture strategy for Enterprises. Enterprises’ result for the six months ended June 30, 2004 compared to the six months ended June 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 Energy Company. Effective January 1, 2004, the operations and assets of Enterprises’ competitive retail sales business, Exelon Energy Company, were transferred to Generation. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of this transfer.

      Exelon Services, Inc. During the six months ended June 30, 2004, Enterprises disposed of certain businesses of Services, including Exelon Solutions and certain businesses of the Mechanical and Integrated Technology Group. Total expected proceeds and the net gain on sale recorded during the six months ended June 30, 2004 related to the disposition of these Services businesses were $34 million and $9 million, respectively. The gain was recorded in other income and deductions on Exelon’s Consolidated Statements of Income and Comprehensive Income. As of June 30, 2004, Services had assets and liabilities of $58 million and $90 million, respectively, which primarily represented the corporate operations and the remaining businesses of the Mechanical and Integrated Technology Group.

      In addition, during the six months ended June 30, 2004, Enterprises disposed of the following business and investment. These dispositions and the transactions described above will affect Enterprises future results of 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 in 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.

      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.

101

---

 

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

		Variance
Transfer of Exelon Energy Company to Generation		$	(504	)
Sale of InfraSource businesses			(262	)
Services(a)			(72	)
F & M Holdings, LLC(b)			(60	)
Other			9
Decrease in operating revenues		$	(889	)

---

(a)		Primarily due to the sale of certain businesses.
(b)		Operating revenues decreased $60 million as a result of the sale of certain businesses and the reduction of new business as a result of wind-down efforts.

     Purchased Power and Fuel Expense. Purchased power and fuel expense decreased as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004.

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

		Variance
Sale of InfraSource businesses		$	(246	)
Services(a)			(56	)
Goodwill impairment charge(b)			(47	)
F & M Holdings, LLC(c)			(43	)
Other			(13	)
Decrease in operating and maintenance expense		$	(405	)

---

(a)		Primarily due to the sale of certain businesses.
(b)		Enterprises recorded a goodwill impairment charge of $47 million during the second quarter of 2003 related to the goodwill recorded within the InfraSource reporting unit.
(c)		Operating and maintenance expense decreased $62 million as a result of wind-down efforts for these businesses. These decreases were partially offset by increased expense of $19 million due to margin deterioration on various construction projects.

     Depreciation and Amortization. Depreciation and amortization expense decreased primarily as a result of the sale of the majority of the InfraSource businesses in the third quarter of 2003 and property, plant and equipment classified as held for sale.

      Other Income and Deductions. The increase in other income and deductions was primarily due to 2004 gains on the sale of Exelon 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 58% for the six months ended June 30, 2004 compared to 38% for the same period in 2003. The increase in the effective tax rate was primarily attributable to state tax impact on the Thermal divestiture and a 16.4% increase of tax expense resulting from various income tax related items.

102

---

 

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 repay maturing 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 weighted toward the third quarter. Energy Delivery’s future cash flows will be affected by its ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings on its revenues. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery. 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 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 six months ended June 30, 2004 and 2003 were $1,907 million and $1,292 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 six months ended June 30, 2004 and 2003:

	•	During the six months ended June 30, 2004, Exelon’s federal income tax position changed from a net federal income tax payable to a net federal income tax receivable. The large increase in cash from the changes in receivables is due primarily to the current year federal income tax provision of approximately $200 million and the receipt of a $150 million federal income tax refund in the first quarter of 2004, partially offset by a $58 million increase in customer accounts receivable and the payment of $67 million for federal income taxes.
	•	Natural gas inventories and deferred natural gas costs decreased $24 million and $56 million, respectively, during the six months ended June 30, 2004 resulting in an $80 million increase to operating cash flows. During 2003, an increase in natural gas inventories of $1 million and an increase in deferred natural gas costs of $24 million resulted in a $25 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.

103

---

 

	•	An increase in required deposits for energy trading activity of $136 million resulted from Generation exceeding its negotiated credit positions with counterparties during the six months ended June 30, 2003. During 2004, required deposits for trading activity resulted in a $2 million net cash inflow.
	•	Discretionary tax-deductible pension plan payments were $288 million for the six months ended June 30, 2004 compared to $246 million for the same period in 2003. Additionally, $42 million and $30 million were contributed to the postretirement welfare benefit plans for the six months ended June 30, 2004 and 2003, respectively.

      Exelon expects to contribute up to approximately $419 million to its pension plans in 2004. These contributions exclude benefit payments expected to be made directly from corporate assets. Of the $419 million expected to be contributed to the pension plans during 2004, $11 million is estimated to be needed to satisfy Internal Revenue Service (IRS) minimum funding requirements.

      Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS to defer the tax gain on the 1999 sale of its fossil generating assets. As of June 30, 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 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 used in investing activities for the six months ended June 30, 2004 and 2003 were $669 million and $1,016 million, respectively. The $347 million reduction of cash used in investing activities in 2004 versus 2003 is primarily attributable to the following:

	•	Cash proceeds of $210 million received during the six months ended June 30, 2004 from the sales of Exelon Thermal, certain businesses of Exelon Services and Enterprises’ investments in PECO TelCove and other equity method investments.
	•	Cash proceeds of $42 million received from the sale of three gas turbines at Generation that were classified as assets held for sale at December 31, 2003.
	•	A decrease in capital expenditures of $89 million net of liquidating damages received in 2003.
	•	An increase in investments in nuclear decommissioning trust funds of $30 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 six months ended June 30, 2004.

104

---

 

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

		Six Months
		Ended June 30,
		2004				2003
Energy Delivery		$	474			$	487
Generation			366				424
Enterprises			—				11
Corporate and other			4				11
Total capital expenditures, net of liquidating damages received		$	844			$	933

      Energy Delivery’s capital expenditures for the six months ended June 30, 2004 reflect 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 $715 million in total capital expenditures for 2004. This represents an increase of approximately $100 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 across the company. 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.

      Generation’s capital expenditures for the six months ended June 30, 2004 reflect additions and upgrades to existing facilities (including nuclear refueling outages), nuclear fuel and increases in capacity at existing plants. Generation’s capital expenditures for the six months ended June 30, 2003 reflected the construction of the Mystic 8 and 9 and Fore River Boston Generating facilities. During 2003, Boston Generating received $86 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 six months ended June 30, 2004 were $937 million compared to $255 million for the same period in 2003. The increase in cash used in financing activities is primarily attributable to the net retirement of $582 million of long-term debt during the six months ended June 30, 2004 versus the net issuance of long-term debt of $334 million during the six months ended June 30, 2003. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding debt issuances and retirements during the six months ended June 30, 2004. During the six months ended June 30, 2004, Exelon repaid $65 million of commercial paper and received cash proceeds of $31 million from the settlement of interest-rate swaps. During the six months ended June 30, 2003, Exelon repaid $100 million of commercial paper and paid $51 million to settle an interest-rate swap. Additionally, Exelon purchased treasury shares totaling $75 million during the second quarter of 2004 and received proceeds from employee stock plans of $140 million and $91 million for the six months ended June 30, 2004 and 2003, respectively.

      The cash dividend payments on common stock for the six months ended June 30, 2004 increased $79 million over the six months ended June 30, 2003, reflecting a 9% increase in the common stock dividend in the third quarter of 2003 and a 10% increase in the first quarter of 2004. Payment of future dividends is subject to approval and declaration by the Board.

      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.

105

---

 

	Credit Issues

      Exelon Credit Facility. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. At June 30, 2004, 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. 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. At June 30, 2004, Exelon Corporate, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

		Bank				Available				Outstanding
Borrower		Sublimit(a)				Capacity(b)				Commercial Paper
Exelon Corporate		$	550			$	531			$	50
ComEd			100				74				—
PECO			250				250				—
Generation			600				460				211

---

(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 175 basis points. For the six months ended June 30, 2004, the average interest rate on notes payable was approximately 1.05%.

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

106

---

 

      Capital Structure. At June 30, 2004, Exelon’s, ComEd’s, PECO’s and Generation’s capital structure consisted of the following:

		Exelon
		Consolidated				ComEd(a)				PECO(a)				Generation
Long-term debt			37	%			33	%			21	%			42	%
Long-term debt to affiliates			24	(b)			15	(b)			61	(b)			—
Common equity			38				52				17				—
Member’s equity			—				—				—				50
Preferred securities			—				—				1				—
Notes payable			1				—				—				7
Minority interest			—				—				—				1

---

(a)		At June 30, 2004, ComEd’s capital structure, excluding the deduction from shareholders’ equity of the $188 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 33% long-term debt, 14% long-term debt to affiliates and 53% common equity. Likewise, PECO’s capital structure, excluding the deduction from shareholder’s equity of the $1.6 billion receivable from Exelon, consisted of 33% common equity, 1% preferred securities and 66% 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. During 2004, ComEd, ComEd of Indiana and PECO had various

107

---

 

										June 30, 2004
		Maximum				Maximum				Contributed
		Invested				Borrowed				(Borrowed)
ComEd		$	487			$	—			$	198
ComEd of Indiana			21				—				21	(a)
PECO			162				—				35
Generation			—				407				(198	)
BSC			—				197				(35	)

---

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

     Sithe Long-Term Debt. At June 30, 2004, $852 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 the ratings on PECO’s First Mortgage Bonds from A to A-. None of the other securities ratings of Exelon, PECO or Exelon subsidiaries has changed. None of Exelon’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.

      Shelf Registration. As of June 30, 2004, Exelon, ComEd and PECO have current shelf registration statements for the sale of $2.0 billion, $555 million and $550 million, respectively, of securities that are effective with the SEC. Exelon’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, the current financial condition of the company, its securities ratings and market conditions.

      PUHCA Restrictions. On April 1, 2004, Exelon obtained a new 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 new financing 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 new order gives Exelon an additional $1.5 billion of guaranty authority. At June 30, 2004, Exelon had provided $1.9 billion of guarantees under the SEC order. 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 June 30, 2004, Exelon’s common equity ratio was 38%. 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 June 30, 2004, Exelon had invested $1.9 billion in EWGs, leaving $2.1 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.

108

---

 

      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 June 30, 2004, Exelon had retained earnings of $2.9 billion, including ComEd’s retained earnings of $1,064 million (all of which had been appropriated for future dividend payments), PECO’s retained earnings of $597 million and Generation’s undistributed earnings of $773 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 June 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 that supports the contractual obligations of Sithe and its subsidiaries.
	•	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.

109

---

 

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 was consistent for the three months ended June 30, 2004 as compared to the same period in 2003.

      ComEd experienced an overall decline in net income of 3% during the six months ended June 30, 2004. This decline primarily reflects lower collections of CTCs, 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.

      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. During the six months ended June 30, 2004, ComEd repaid $178 million of long-term debt and made a $179 million payment on long-term debt to ComEd Transitional Funding Trust. ComEd met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.

      Regulatory Developments — PJM Integration. On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM. The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of the transmission assets of ComEd and other new members, subject to a compliance filing and hearing on certain issues. 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 March 18, 2004, the FERC approved ComEd’s plan to complete its integration into PJM, subject to the North American Electric Reliability Council (NERC) approval of the PJM and Midwest ISO reliability plans to assure no adverse effects. The NERC granted the required approval on April 2, 2004. On April 27, 2004, the FERC issued its order approving ComEd’s application, subject to certain stipulations, including a provision to hold certain other utilities harmless from the impacts of ComEd joining PJM. ComEd agreed to these stipulations and fully integrated into PJM on May 1, 2004.

      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, 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 Rates. ComEd currently earns approximately $66 million annually 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 and Midwest ISO and other parties must file one or more pricing proposals with the FERC on or before October 1, 2004, with an effective date of December 1, 2004. While Exelon and ComEd cannot predict the outcome of the FERC’s final determination of a new long-term transmission pricing structure, such pricing structure could adversely impact Exelon’s and ComEd’s after-tax results of operations.

      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

110

---

 

      Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. 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. ComEd began charging the new rates May 1, 2004. ComEd’s management believes an adequate reserve for any required refunds has been established in the event that the new rates are adjusted based on rehearing or settlement negotiations.

      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.

Results of Operations

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

				Three Months
				Ended June 30,
				2004				2003				Variance				% Change
Operating revenues				$	1,403			$	1,361			$	42				3.1	%
Operating expenses
	Purchased power				574				533				41				7.7	%
	Operating and maintenance				223				221				2				0.9	%
	Depreciation and amortization				103				96				7				7.3	%
	Taxes other than income				72				68				4				5.9	%
		Total operating expense			972				918				54				5.9	%
Operating income					431				443				(12	)			(2.7	)%
Other income and deductions
	Interest expense				(96	)			(106	)			10				(9.4	)%
	Distributions on mandatorily redeemable preferred securities				—				(6	)			6				(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates				(6	)			—				(6	)			n.m.
	Other, net				7				12				(5	)			(41.7	)%
		Total other income and deductions			(95	)			(100	)			5				(5.0	)%
Income before income taxes					336				343				(7	)			(2.0	)%
Income taxes					132				138				(6	)			(4.3	)%
Net income				$	204			$	205			$	(1	)			(0.5	)%

---

n.m. — not meaningful

111

---

 

	Operating Revenues

      ComEd’s electric sales statistics were as follows:

			Three Months
			Ended June 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				5,793				5,163				630				12.2	%
Small commercial & industrial				4,791				5,114				(323	)			(6.3	)%
Large commercial & industrial				1,426				1,683				(257	)			(15.3	)%
Public authorities & electric railroads				1,200				1,333				(133	)			(10.0	)%
	Total full service			13,210				13,293				(83	)			(0.6	)%
PPO
Small commercial & industrial				870				869				1				0.1	%
Large commercial & industrial				877				1,318				(441	)			(33.5	)%
Public authorities & electric railroads				577				531				46				8.7	%
				2,324				2,718				(394	)			(14.5	)%
Delivery only(b)
Small commercial & industrial				1,761				1,257				504				40.1	%
Large commercial & industrial				3,090				2,128				962				45.2	%
Public authorities & electric railroads				406				247				159				64.4	%
				5,257				3,632				1,625				44.7	%
	Total PPO and delivery only			7,581				6,350				1,231				19.4	%
Total retail deliveries				20,791				19,643				1,148				5.8	%

---

(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.

112

---

 

			Three Months
			Ended June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	521			$	472			$	49				10.4	%
Small commercial & industrial				396				405				(9	)			(2.2	)%
Large commercial & industrial				71				84				(13	)			(15.5	)%
Public authorities & electric railroads				74				81				(7	)			(8.6	)%
	Total full service			1,062				1,042				20				1.9	%
PPO(b)
Small commercial & industrial				60				59				1				1.7	%
Large commercial & industrial				51				72				(21	)			(29.2	)%
Public authorities & electric railroads				31				28				3				10.7	%
				142				159				(17	)			(10.7	)%
Delivery only(c)
Small commercial & industrial				35				32				3				9.4	%
Large commercial & industrial				43				43				—				—
Public authorities & electric railroads				9				8				1				12.5	%
				87				83				4				4.8	%
Total PPO and delivery only				229				242				(13	)			(5.4	)%
Total electric retail revenues				1,291				1,284				7				0.5	%
Wholesale and miscellaneous revenue(d)				112				77				35				45.5	%
Total electric revenue			$	1,403			$	1,361			$	42				3.1	%

---

(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 ComEd’s 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.

113

---

 

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

			Variance
Volume			$	61
Weather				29
Customer choice				(51	)
Rate changes				(28	)
Other				(4	)
	Electric retail revenue			7
ComEd’s integration into PJM				43
Other				(8	)
	Wholesale and miscellaneous revenue			35
	Total electric retail revenue		$	42

      Volume. Revenues from higher delivery volume, exclusive of weather, increased $61 million due to increased residential customer growth and an increased usage per customer, primarily residential and large commercial and industrial.

      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 June 30, 2004 were favorable compared to the same period in 2003. Cooling degree-days increased 68% for the three months ended June 30, 2004 compared to the same period in 2003, and were 14% lower than normal. Heating degree-days decreased 18% for the three months ended June 30, 2004 compared to the same period in 2003, and were 13% lower than normal.

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

      For the three months ended June 30, 2004, the energy provided by AESs was 5,257 GWhs, or 25%, as compared to 3,632 GWhs, or 18%, 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 June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of the same period in 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 6.3 million for the three months ended June 30, 2003 to 7.6 million for three months ended June 30, 2004, or from 32% to 36% of total quarterly retail deliveries.

      Rate Changes. ComEd’s CTC is reset in the second quarter of each year to reflect market price adjustments. 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. ComEd’s CTC revenues decreased $44 million for the three months ended June 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 ComEd’s PPO by $28 million.

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

114

---

 

      ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the three months ended June 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 and a $10 million increase due to favorable weather conditions offset by a $40 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 $43 million in the three months ended June 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 June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Higher corporate allocations(a)		$	17
Severance, pension and postretirement benefit costs associated with The Exelon Way			8
Tax consultant fees(b)			5
Employee fringe benefits(c)			(10	)
Contractors			(11	)
Environmental charges			(4	)
Other			(3	)
Increase in operating and maintenance expense		$	2

---

(a)		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 Enterprise companies resulting in ComEd comprising a greater percentage of Exelon.
(b)		ComEd recorded a $5 million charge for contingent fees paid to a tax consultant (see Note 15 of the Combined Notes to Consolidated Financial Statements for more information).
(c)		During the second quarter of 2004, ComEd 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 June 30,
		2004				2003				Variance				% Change
Depreciation expense		$	81			$	76			$	5				6.6	%
Recoverable transition costs amortization			12				12				—				—
Other amortization expense			10				8				2				25.0	%
Total depreciation and amortization		$	103			$	96			$	7				7.3	%

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

115

---

 

      Recoverable transition costs amortization remained constant in the three months ended June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $109 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 increased for three months ended June 30, 2004 as compared to the same period in 2003 as a result of a 2003 refund of $5 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 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

      In 2004, ComEd has $6 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.

	Other, Net

      The change in Other, net is primarily related to the 2003 $2 million gain on sale of non-utility property 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 39% for the three months ended June 30, 2004, compared to 40% for the three months ended June 30, 2003. The decrease in the effective tax rate was primarily attributable to the adoption of FSP FAS 106-2 and other items. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

116

---

 

	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

				Six Months
				Ended June 30,
				2004				2003				Variance				% Change
Operating revenues				$	2,739			$	2,785			$	(46	)			(1.7	)%
Operating expenses
	Purchased power				1,108				1,110				(2	)			(0.2	)%
	Operating and maintenance				438				483				(45	)			(9.3	)%
	Depreciation and amortization				205				190				15				7.9	%
	Taxes other than income				151				148				3				2.0	%
		Total operating expense			1,902				1,931				(29	)			(1.5	)%
Operating income					837				854				(17	)			(2.0	)%
Other income and deductions
	Interest expense				(202	)			(215	)			13				(6.0	)%
	Distributions on mandatorily redeemable preferred securities				—				(14	)			14				(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates				(9	)			—				(9	)			n.m.
	Other, net				17				34				(17	)			(50.0	)%
		Total other income and deductions			(194	)			(195	)			1				(0.5	)%
Income before income taxes and cumulative effect of a change in accounting principle					643				659				(16	)			(2.4	)%
Income taxes					255				263				(8	)			(3.0	)%
Net income before cumulative effect of a change in accounting principle					388				396				(8	)			(2.0	)%
Cumulative effect of a change in accounting principle					—				5				(5	)			(100.0	)%
Net income				$	388			$	401			$	(13	)			(3.2	)%

---

n.m. — not meaningful

117

---

 

	Operating Revenues

      ComEd’s electric sales statistics were as follows:

			Six Months
			Ended June 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				12,805				12,049				756				6.3	%
Small commercial & industrial				9,924				10,741				(817	)			(7.6	)%
Large commercial & industrial				2,771				3,167				(396	)			(12.5	)%
Public authorities & electric railroads				2,440				2,749				(309	)			(11.2	)%
	Total full service			27,940				28,706				(766	)			(2.7	)%
PPO
Small commercial & industrial				1,600				1,662				(62	)			(3.7	)%
Large commercial & industrial				1,624				2,750				(1,126	)			(40.9	)%
Public authorities & electric railroads				1,012				1,069				(57	)			(5.3	)%
				4,236				5,481				(1,245	)			(22.7	)%
Delivery only(b)
Small commercial & industrial				3,532				2,606				926				35.5	%
Large commercial & industrial				6,031				3,960				2,071				52.3	%
Public authorities & electric railroads				894				529				365				69.0	%
				10,457				7,095				3,362				47.4	%
	Total PPO and delivery only			14,693				12,576				2,117				16.8	%
Total retail deliveries				42,633				41,282				1,351				3.3	%

---

(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.

118

---

 

			Six Months
			Ended June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	1,080			$	1,018			$	62				6.1	%
Small commercial & industrial				769				802				(33	)			(4.1	)%
Large commercial & industrial				131				158				(27	)			(17.1	)%
Public authorities & electric railroads				148				165				(17	)			(10.3	)%
	Total full service			2,128				2,143				(15	)			(0.7	)%
PPO(b)
Small commercial & industrial				108				109				(1	)			(0.9	)%
Large commercial & industrial				92				144				(52	)			(36.1	)%
Public authorities & electric railroads				53				55				(2	)			(3.6	)%
				253				308				(55	)			(17.9	)%
Delivery only(c)
Small commercial & industrial				67				73				(6	)			(8.2	)%
Large commercial & industrial				84				91				(7	)			(7.7	)%
Public authorities & electric railroads				18				17				1				5.9	%
				169				181				(12	)			(6.6	)%
Total PPO and delivery only				422				489				(67	)			(13.7	)%
Total electric retail revenues				2,550				2,632				(82	)			(3.1	)%
Wholesale and miscellaneous revenue(d)				189				153				36				23.5	%
Total electric revenue			$	2,739			$	2,785			$	(46	)			(1.7	)%

---

(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 ComEd’s 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 form PJM), sales to municipalities and other wholesale energy sales.

119

---

 

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

			Variance
Customer choice			$	(107	)
Rate changes				(70	)
Volume				92
Weather				6
Other				(3	)
	Electric retail revenue		$	(82	)
ComEd’s integration into PJM				43
Other				(7	)
	Wholesale and miscellaneous revenue			36
	Electric retail revenue		$	(46	)

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

      For the six months ended June 30, 2004, the energy provided by AESs was 10,457 GWhs, or 25%, as compared to 7,095 GWhs, or 17%, 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 June 30, 2004, the number of retail customers that had elected to purchase energy from an AES or the ComEd PPO was approximately 21,400 as compared to 22,000 as of June 30, 2003, representing less than 1% of total customers in each period. MWhs delivered to such customers increased from approximately 12.6 million for the six months ended June 30, 2003 to approximately 14.7 million for six months ended June 30, 2004, or from 30% to 34% of total quarterly retail deliveries.

      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 $120 million for the six months ended June 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 ComEd’s PPO by $47 million. For the six months ended June 30, 2004 and June 30, 2003, ComEd collected approximately $87 million and $207 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 commercial and industrial.

      Weather. The weather conditions for the six months ended June 30, 2004 were favorable compared to the same period in 2003. Cooling degree-days increased 68% for the six months ended June 30, 2004 compared to the same period in 2003 and were 14% lower than normal. Heating degree-days decreased 8% for the six months ended June 30, 2004 compared to the same period in 2003, and were 4% lower than normal.

      ComEd’s Integration into PJM. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 30, 2004 relative to 2003 due to ComEd’s May 1, 2004 entry into PJM.

120

---

 

	Purchased Power

      The decrease in purchased power expense was primarily attributable to a $92 million decrease as a result of customers choosing to purchase energy from an AES and an $8 million decrease due to the mix of average pricing related to ComEd’s PPA with Generation partially offset by an increase of $50 million due to higher volume. ComEd’s transmission revenues and purchased power expense each increased by $43 million in the six months ended June 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 six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Charge recorded at ComEd in 2003(a)		$	(41	)
Contractors			(13	)
Decreased payroll expense due to fewer employees(b)			(10	)
Environmental charges			(5	)
Allowance for uncollectible accounts expense			(4	)
Higher corporate allocations(c)			23
Severance, pension and postretirement benefit costs associated with The Exelon Way			9
Tax consultant fees(d)			5
Employee fringe benefits(e)			1
Other			(10	)
Decrease in operating and maintenance expense		$	(45	)

---

(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)		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 Enterprise companies resulting in ComEd comprising a greater percentage of Exelon.
(d)		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).
(e)		During the second quarter of 2004, ComEd adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $3 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

	Depreciation and Amortization

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Depreciation expense		$	163			$	152			$	11				7.2	%
Recoverable transition costs amortization			23				23				—				—
Other amortization expense			19				15				4				26.7	%
Total depreciation and amortization		$	205			$	190			$	15				7.9	%

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

      Recoverable transition costs amortization remained constant in the six months ended June 30, 2004 compared to the same period in 2003. ComEd expects to fully recover its remaining recoverable transition costs regulatory asset balance of $109 million by 2006. Consistent with the provision of the Illinois legislation,

121

---

 

	Taxes Other Than Income

      Taxes other than income increased for six months ended June 30, 2004 as compared to the same period in 2003 as a result of a 2003 refund of $5 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 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 $3 million of less allowance for funds used during construction (AFUDC) debt recorded during the six months ended June 30, 2004 as a result of lower construction work in process balances.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      In 2004, ComEd has $9 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.

	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 AFUDC equity of $4 million during 2004 as a result of lower construction work in process balances and a $3 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 40% for the six months ended June 30, 2004, compared to 40% for the six months ended June 30, 2003. The reduction in the effective tax rate is primarily attributable to 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, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.

122

---

 

	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 six months ended June 30, 2004 and 2003 were $602 million and $369 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 six months ended June 30, 2004 and 2003 were affected by the following items:

	•	During the first half of 2003, ComEd made additional payments to Generation for amounts owed under the PPA. At June 30, 2004 and December 31, 2003, ComEd had accrued payments due to Generation under the PPA of $182 million and $171 million, respectively. At June 30, 2003 and December 31, 2002, ComEd had accrued payments due to Generation under the PPA of $185 million and $339 million, respectively.
	•	Discretionary contributions by ComEd to Exelon’s defined benefit pension plans were $144 million for the six months ended June 30, 2004 compared to $117 million for the same period in 2003.

      ComEd participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $216 million is expected to be funded by ComEd.

      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 June 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 used in investing activities were $133 million for the six months ended June 30, 2004 compared to cash flows used in investing activities of $524 million for the same period in 2003. The change in cash flows from investing activities was primarily attributable to $372 million of net proceeds from an investment in the Exelon intercompany money pool and $36 million of net changes in restricted cash. ComEd’s investing activities for the six months ended June 30, 2004 were funded primarily through operating activities.

      ComEd’s capital expenditures for the six months ended June 30, 2004 and 2003 were $369 million and $355 million, respectively. ComEd estimates that it will spend up to approximately $715 million in total

123

---

 

	Cash Flows from Financing Activities

      Cash flows used in financing activities for the six months ended June 30, 2004 were $476 million as compared to cash flows from financing activities of $173 million in 2003. The decrease in cash flows from financing activities is primarily attributable to the retirement of long-term debt of $357 million during the six months ended June 30, 2004 versus the net proceeds from the issuance of long-term debt of $473 million during the same period in 2003. During the six months ended June 30, 2003, ComEd also repaid $71 million of commercial paper and paid $51 million to settle interest-rate swaps. During the six months ended June 30, 2004, ComEd received $26 million from the settlement of interest-rate swaps. Additionally, ComEd paid $207 million in dividends to Exelon during the six months ended June 30, 2004 compared to $211 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.

	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. 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 June 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 six months ended June 30, 2004, ComEd earned $2 million in interest on its investments 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 June 30, 2004, ComEd has a current shelf registration statement for the sale of $555 million of securities that is effective with the SEC. 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 June 30, 2004, ComEd had retained earnings of $1,064 million, which 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

124

---

 

	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 June 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.

125

---

 

	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 increased 14% for the three months ended June 30, 2004 as compared to the same period in 2003. This increase reflects higher electric revenues, partially offset by higher operating expenses.

      PECO’s net income increased 4% for the six months ended June 30, 2004 as compared to the same period in 2003 and is generally comparable 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 six months ended June 30, 2004, PECO refinanced $75 million of First and Refunding Mortgage Bonds and repaid $166 million of long-term debt to PECO Energy Transition Trust. PECO met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.

      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.

126

---

 

Results of Operations

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

				Three Months
				Ended June 30,
				2004				2003				Variance				% Change
Operating revenues				$	1,032			$	961			$	71				7.4	%
Operating expenses
	Purchased power				402				386				16				4.1	%
	Fuel				83				67				16				23.9	%
	Operating and maintenance				132				121				11				9.1	%
	Depreciation and amortization				125				116				9				7.8	%
	Taxes other than income				60				47				13				27.7	%
		Total operating expenses			802				737				65				8.8	%
Operating income					230				224				6				2.7	%
Other income and deductions
	Interest expense				(76	)			(83	)			7				(8.4	)%
	Distributions on mandatorily redeemable preferred securities				—				(2	)			2				(100.0	)%
	Equity in losses of unconsolidated affiliates				(7	)			—				(7	)			n.m.
	Other, net				3				1				2				n.m.
		Total other income and deductions			(80	)			(84	)			4				(4.8	)%
Income before income taxes					150				140				10				7.1	%
Income taxes					50				52				(2	)			(3.8	)%
Net income					100				88				12				13.6	%
Preferred stock dividends					1				2				(1	)			(50.0	)%
Net income on common stock				$	99			$	86			$	13				15.1	%

---

n.m. — not meaningful

127

---

 

	Operating Revenue

      PECO’s electric sales statistics were as follows:

			Three Months
			Ended June 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				2,272				2,274				(2	)			(0.1	)%
Small commercial & industrial				1,686				1,532				154				10.1	%
Large commercial & industrial				3,703				3,695				8				0.2	%
Public authorities & electric railroads				224				222				2				0.9	%
	Total full service			7,885				7,723				162				2.1	%
Delivery only(b)
Residential				488				186				302				162.4	%
Small commercial & industrial				433				323				110				34.1	%
Large commercial & industrial				190				192				(2	)			(1.0	)%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			1,111				701				410				58.5	%
Total retail deliveries				8,996				8,424				572				6.8	%

---

(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 June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	298			$	297			$	1				0.3	%
Small commercial & industrial				197				180				17				9.4	%
Large commercial & industrial				281				267				14				5.2	%
Public authorities & electric railroads				20				21				(1	)			(4.8	)%
	Total full service			796				765				31				4.1	%
Delivery only(b)
Residential				38				14				24				171.4	%
Small commercial & industrial				23				17				6				35.3	%
Large commercial & industrial				5				5				—				—
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			66				36				30				83.3	%
Total electric retail revenues				862				801				61				7.6	%
Wholesale and miscellaneous revenue(d)				51				50				1				2.0	%
Total electric revenue			$	913			$	851			$	62				7.3	%

---

(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.

128

---

 

(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 June 30, 2004, as compared to the same period in 2003, were as follows:

		Variance
Volume		$	46
Weather			14
Rate mix			12
Rate change			5
Customer choice			(16	)
Retail revenue		$	61

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

      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 favorable compared to the prior year. Cooling degree-days increased 66% and heating degree-days decreased 32%.

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

      Rate change. Revenues increased $5 million due to a scheduled phase-out of merger-related rate reductions. In connection with the PUC’s approval of the merger of PECO, Unicom Corporation, and Exelon in 2000, PECO entered into a settlement agreement with the PUC and agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005. Rates were reduced by $60 million per year in 2002 and 2003 and will be reduced by $40 million per year in 2004 and 2005.

      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 June 30, 2004, the energy provided by AESs was 1,111 GWhs, or 12%, as compared to 701 GWhs, or 8%, for the three months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 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.

      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.

129

---

 

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

		Three Months
		Ended June 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			8,162				9,222				(1,060	)			(11.5	)%
Transportation			6,410				5,779				631				10.9	%
Total			14,572				15,001				(429	)			(2.9	)%

		Three Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Retail sales		$	102			$	99			$	3				3.0	%
Transportation			4				4				—				—
Resales and other			13				7				6				85.7	%
Total		$	119			$	110			$	9				8.2	%

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

		Variance
Rate changes		$	13
Volume			4
Weather			(14	)
Total gas retail revenues		$	3

      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 June 1, 2003 and March 1, 2004. The average rate per mmcf for the three months ended June 30, 2004 was 30% 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 has asked the PUC for a decrease in its rates through the purchased gas adjustment clause effective December 1, 2004 as a result of lower current gas costs. This proposed decrease would have no impact on PECO’s operating income.

      Volume. Exclusive of the effect of weather conditions, revenues were higher due primarily to increased sales in the residential and small commercial and industrial classes.

      Weather. The weather conditions were unfavorable compared to the prior year. Heating degree-days decreased 32%.

      Resales and other revenue increased $6 million primarily due to increased off-system sales.

	Purchased Power

      The increase in purchased power expense was attributable to $16 million of increased sales exclusive of the effect of weather conditions, $14 million of higher prices, and $6 million related to higher sales due to favorable weather conditions, offset by $16 million from customers in Pennsylvania assigned to or selecting an AES and $4 million of lower PJM transmission expense.

130

---

 

	Fuel

      The increase in fuel expense was attributable to $13 million of higher gas costs, $10 million related to increased off-system sales, and $3 million related to increased sales exclusive of weather conditions, partially offset by a $10 million decrease associated with lower sales due to unfavorable weather conditions.

	Operating and Maintenance

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

		Variance
Higher corporate allocations(a)		$	12
Severance, pension and postretirement benefit costs associated with The Exelon Way			4
Decreased payroll expense due to fewer employees(b)			(4	)
Employee fringe benefits(c)			(5	)
Other			4
Increase in operating and maintenance expense		$	11

---

(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sales of certain Enterprises businesses.
(b)		PECO has fewer employees as a result of The Exelon Way.
(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 June 30,
		2004				2003				Variance				% Change
Competitive transition charge amortization		$	86			$	79			$	7				8.9	%
Depreciation expense			33				33				—				—
Other amortization expense			6				4				2				50.0	%
Total depreciation and amortization		$	125			$	116			$	9				7.8	%

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

	Taxes Other Than Income

      The increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual resulting from an audit settlement in 2003.

	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. 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.

131

---

 

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      In 2004, PECO has $7 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.

	Other, Net

      The increase was attributable to a $2 million increase in interest income.

	Income Taxes

      The effective tax rate was 33% for the three months ended June 30, 2004 as compared to 37% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. 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

	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

				Six Months
				Ended June 30,
				2004				2003				Variance				% Change
Operating revenues				$	2,271			$	2,178			$	93				4.3	%
Operating expenses
	Purchased power				799				808				(9	)			(1.1	)%
	Fuel				332				257				75				29.2	%
	Operating and maintenance				266				261				5				1.9	%
	Depreciation and amortization				250				236				14				5.9	%
	Taxes other than income				118				110				8				7.3	%
		Total operating expenses			1,765				1,672				93				5.6	%
Operating income					506				506				—				—
Other income and deductions
	Interest expense				(153	)			(168	)			15				(8.9	)%
	Distributions on mandatorily redeemable preferred securities				—				(5	)			5				(100.0	)%
	Equity in earnings (losses) of unconsolidated affiliates				(13	)			—				(13	)			n.m.
	Other, net				5				10				(5	)			(50.0	)%
		Total other income and deductions			(161	)			(163	)			2				(1.2	)%
Income before income taxes					345				343				2				0.6	%
Income taxes					112				119				(7	)			(5.9	)%
Net income					233				224				9				4.0	%
Preferred stock dividends					2				3				(1	)			(33.3	)%
Net income on common stock				$	231			$	221			$	10				4.5	%

---

n.m. — not meaningful

132

---

 

	Operating Revenue

      PECO’s electric sales statistics were as follows:

			Six Months
			Ended June 30,
Retail Deliveries — (in GWhs)			2004				2003				Variance				% Change
Full service(a)
Residential				5,016				5,389				(373	)			(6.9	)%
Small commercial & industrial				3,370				3,312				58				1.8	%
Large commercial & industrial				7,320				7,177				143				2.0	%
Public authorities & electric railroads				453				475				(22	)			(4.6	)%
	Total full service			16,159				16,353				(194	)			(1.2	)%
Delivery only(b)
Residential				1,070				450				620				137.8	%
Small commercial & industrial				857				525				332				63.2	%
Large commercial & industrial				340				402				(62	)			(15.4	)%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			2,267				1,377				890				64.6	%
Total retail deliveries				18,426				17,730				696				3.9	%

---

(a)		Full service reflects deliveries to customers taking electric service under tariffed rates.
(b)		Delivery only service reflects customers receiving electric generation service from an AES.
(c)		PECO’s delivery only sales to Public Authorities and Electric Railroads were less than one GWh per quarter.

			Six Months
			Ended June 30,
Electric Revenue			2004				2003				Variance				% Change
Full service(a)
Residential			$	611			$	656			$	(45	)			(6.9	)%
Small commercial & industrial				374				374				—				—
Large commercial & industrial				551				534				17				3.2	%
Public authorities & electric railroads				40				42				(2	)			(4.8	)%
	Total full service			1,576				1,606				(30	)			(1.9	)%
Delivery only(b)
Residential				80				31				49				158.1	%
Small commercial & industrial				43				27				16				59.3	%
Large commercial & industrial				9				11				(2	)			(18.2	)%
Public authorities & electric railroads(c)				—				—				—				—
	Total delivery only			132				69				63				91.3	%
Total electric retail revenues				1,708				1,675				33				2.0	%
Wholesale and miscellaneous revenue(d)				99				104				(5	)			(4.8	)%
Total electric revenue			$	1,807			$	1,779			$	28				1.6	%

---

(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.

133

---

 

(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 six months ended June 30, 2004, as compared to the same period in 2003, were as follows:

		Variance
Volume		$	66
Rate change			9
Weather			7
Customer choice			(42	)
Rate mix			(7	)
Retail revenue		$	33

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

      Rate change. Revenues increased $9 million due to a scheduled phase-out of merger-related rate reductions.

      Weather. The weather impact was favorable compared to the prior year. Cooling degree-days increased 66% and heating degree-days decreased 8%.

      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 six months ended June 30, 2004, the energy provided by AESs was 2,267 GWhs, or 12%, as compared to 1,377 GWhs, or 8%, for the six months ended June 30, 2003. As of June 30, 2004, the number of customers served by AESs was 292,100, or 19%, as compared to 125,000, or 8%, as of June 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 six months ended June 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 $5 million primarily due to lower PJM transmission revenue.

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

		Six Months
		Ended June 30,
Deliveries to customers (in mmcf)		2004				2003				Variance				% Change
Retail sales			37,965				40,685				(2,720	)			(6.7	)%
Transportation			13,542				13,942				(400	)			(2.9	)%
Total			51,507				54,627				(3,120	)			(5.7	)%

134

---

 

			Six Months
			Ended June 30,
Revenue			2004				2003				Variance				% Change
Retail sales			$	431			$	372			$	59				15.9	%
Transportation				9				9				—				—
Resales and other				24				18				6				33.3	%
	Total		$	464			$	399			$	65				16.3	%

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

		Variance
Rate changes		$	82
Weather			(19	)
Volume			(4	)
Total gas retail revenues		$	59

      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 six months ended June 30, 2004 was 39% 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 six months ended June 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 $6 million primarily due to increased off-system sales.

	Purchased Power

      The decrease in purchased power expense was attributable to $42 million from customers in Pennsylvania assigned to or selecting an AES and a $9 million decrease in PJM transmission expense, partially offset by an increase of $31 million related to increased sales exclusive of weather conditions, $8 million of higher prices, and a $3 million increase associated with higher sales due to favorable weather conditions.

	Fuel

      The increase in fuel expense was attributable to $82 million of higher gas costs and $13 million related to increased off-system sales, partially offset by a $16 million decrease associated with lower sales due to unfavorable weather conditions and a decrease of $4 million related to decreased sales exclusive of the effect of weather conditions.

135

---

 

	Operating and Maintenance

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

		Variance
Higher corporate allocations(a)		$	19
Severance, pension and postretirement benefit costs associated with The Exelon Way			10
Decreased payroll expense due to fewer employees(b)			(11	)
Employee fringe benefits(c)			(4	)
Allowance for uncollectible accounts expense			(2	)
Other			(7	)
Increase in operating and maintenance expense		$	5

---

(a)		Higher corporate allocations primarily result from a higher percentage allocation to Energy Delivery due to the sales of certain Enterprises businesses.
(b)		PECO has fewer employees as a result of The Exelon Way terminations.
(c)		During the second quarter of 2004, PECO adopted the provisions of FSP FAS 106-2. Employee fringe benefits include a $2 million reduction in net periodic postretirement benefit cost due to the adoption of FSP FAS 106-2.

	Depreciation and Amortization

		Six Months
		Ended June 30,
		2004				2003				Variance				% Change
Competitive transition charge amortization		$	174			$	161			$	13				8.1	%
Depreciation expense			66				66				—				—
Other amortization expense			10				9				1				11.1	%
Total depreciation and amortization		$	250			$	236			$	14				5.9	%

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

	Taxes Other Than Income

      The increase in taxes other than income was primarily attributable to $12 million related to the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $6 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. 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 Earnings (Losses) of Unconsolidated Affiliates

      In 2004, PECO recorded $13 million of equity in net losses of subsidiaries as a result of deconsolidating its subsidiary financing trusts.

136

---

 

	Other, Net

      The decrease was attributable to a $2 million decrease in interest income and a $4 million favorable settlement of a customer contract in 2003.

	Income Taxes

      The effective tax rate was 33% for the six months ended June 30, 2004 as compared to 35% for the same period in 2003. The decrease in the effective tax rate was primarily attributable to plant-related differences. 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, repayments of maturing 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 six months ended June 30, 2004 and 2003 were $509 million and $425 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 six months ended June 30, 2004 and 2003 were affected by the following items:

	•	Deferred natural gas costs decreased $56 million during the six months ended June 30, 2004 resulting in an increase to operating cash flows. During 2003, an increase in deferred natural gas costs of $24 million resulted in a decrease to operating cash flows. 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.
	•	Discretionary contributions by PECO to Exelon’s defined benefit pension plans were $5 million during the six months ended June 30, 2004 compared to $12 million for the same period in 2003.

      PECO participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $8 million is expected to be funded by PECO.

137

---

 

	Cash Flows from Investing Activities

      Cash flows used in investing activities for the six months ended June 30, 2004 and 2003 were $137 million and $98 million, respectively. The $39 million increase in cash used in investing activities was primarily attributable to a $35 million investment in the Exelon intercompany money pool in 2004 and a change in restricted cash which provided cash flows of $28 million in 2003, partially offset by lower construction expenditures of $27 million in 2004. PECO’s investing activities during the six months ended June 30, 2004 were funded by operating activities.

      PECO’s projected capital expenditures for 2004 are $233 million. Approximately 60% of the budgeted 2004 expenditures are 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 six months ended June 30, 2004 were $317 million compared to $329 million for the same period in 2003. The decrease in cash flows used in financing activities is primarily due to a decrease in the retirement of preferred securities of $100 million and an increase in contributions received from Exelon of $54 million, partially offset by an increase in net retirements of long-term debt of $124 million. Additionally, PECO paid dividends of $182 million and $168 during the six months ended June 30, 2004 and 2003, respectively, of which $180 million and $165 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 meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. PECO participates, 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 June 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 six months ended June 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 the ratings on PECO’s First Mortgage Bonds from A to A-. None of PECO’s other securities ratings has changed. 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.

138

---

 

      Shelf Registration. As of June 30, 2004, PECO has a current shelf registration statement for the sale of $550 million of securities that is effective with the SEC. 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 June 30, 2004, PECO had retained earnings of $597 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 June 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.

139

---

 

EXELON GENERATION COMPANY, LLC

General

      Generation operates as a single segment and consists of electric generating facilities, energy marketing operations, a 50% interest in Sithe 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. 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 six months ended June 30, 2003 were as follows:

		Three Months				Six Months
		Ended June 30,				Ended June 30,
		2003				2003
Total revenues		$	174			$	504
Intersegment revenues			2				9
Income (loss) before income taxes			1				(16	)
Income taxes (benefit)			1				(6	)
Net income (loss)			—				(10	)

Executive Overview

      Financial Results. Generation reported an overall increase in net income of $36 million for the quarter ended June 30, 2004 as compared to the prior year, due primarily to the gain of $52 million, net of income taxes, recorded on the sale of Boston Generating, partially offset by operating net losses of $10 million for Boston Generating, incurred during the second quarter of 2004. Generation reported an overall increase in net income of $83 million for the six months ended June 30, 2004 as compared to the same period in 2003. This increase was primarily attributable to 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 for Boston Generating incurred during the first five months of 2004, $43 million 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. Generation’s results of operations for the six months ended June 30, 2003 included the pre-tax impairment charge on Generation’s investment in Sithe of $200 million and a $108 million net gain resulting from the cumulative effect of a change in accounting principle for the adoption of SFAS 143.

      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.

      Divestiture Activities. During the second quarter, Generation completed the sale and transfer of the assets of Boston Generating to a special purpose entity formed by the lenders of the Boston Generating credit facility.

      In connection with the consolidation of Sithe, Generation recorded assets held for sale related to Sithe’s investments in certain hydroelectric facilities. At June 30, 2004, Generation’s consolidated balance sheets reflect $9 million of assets, and $3 million of liabilities held for sale related to these investments. Generation continues to explore various transactional strategies related to its investment in Sithe.

      Financing Activities. On June 30, 2004, Generation had $211 million of commercial paper outstanding and $198 million in outstanding money pool loans to fund operations. Also, Generation increased its distributions to Exelon by approximately $64 million during the first six months of 2004 compared to the same period in the prior year. Generation continues to meet its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.

140

---

 

      Operations. Generation’s nuclear fleet achieved a 93.3% capacity factor during the six months ended June 30, 2004 compared to 94.2% during the same period in 2003, primarily as a result of an increased number of planned outages in 2004 as compared to 2003. Generation anticipates transferring plant operations and power marketing activities of Boston Generating to a special purpose entity designated by the lenders of the Boston Generating credit facility during the third quarter of 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 June 30, 2004 Compared to Three Months Ended June 30, 2003

				Three Months
				Ended June 30,
				2004				2003				Variance				% Change
Operating revenues				$	1,948			$	1,886			$	62				3.3	%
Operating expenses
	Purchased power				563				800				(237	)			(29.6	)%
	Fuel				462				348				114				32.8	%
	Operating and maintenance				623				451				172				38.1	%
	Depreciation and amortization				69				46				23				50.0	%
	Taxes other than income				48				40				8				20.0	%
		Total operating expenses			1,765				1,685				80				4.7	%
Operating income					183				201				(18	)			(9.0	)%
Other income and deductions
	Interest expense				(51	)			(20	)			(31	)			155.0	%
	Equity in earnings of unconsolidated affiliates				—				18				(18	)			(100.0	)%
	Other, net				134				34				100				n.m.
		Total other income and deductions			83				32				51				159.4	%
Income before income taxes and minority interest					266				233				33				14.2	%
Income taxes					100				91				9				9.9	%
Income before minority interest					166				142				24				16.9	%
Minority interest					12				—				12				n.m.
Net income				$	178			$	142			$	36				25.4	%

---

n.m. — not meaningful

141

---

 

	Operating Revenues

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

		Three Months
		Ended June 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates(a)		$	846			$	877			$	(31	)			(3.5	)%
Wholesale and retail electric sales(b)			858				897				(39	)			(4.3	)%
Total electric energy sales revenue			1,704				1,774				(70	)			(3.9	)%
Retail gas sales			84				—				84				n.m.
Trading portfolio			(2	)			(1	)			(1	)			100.0	%
Other revenue(c)			162				113				49				43.4	%
Total revenue		$	1,948			$	1,886			$	62				3.3	%

---

(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 June 30,
Sales (in GWhs)		2004(c)				2003				Variance				% Change
Sales to affiliates(a)			26,133				26,869				(736	)			(2.7	)%
Wholesale and retail electric sales(b)			24,976				27,449				(2,473	)			(9.0	)%
Total sales			51,109				54,318				(3,209	)			(5.9	)%

---

(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 6,185 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 5,324 GWhs and 7,919 GWhs for the three months ended June 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.

142

---

 

      Generation’s average margin and other operating data for the three months ended June 30, 2004 and 2003 are as follows:

			Three Months
			Ended June 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates(a)		$	32.37			$	32.64				(0.8	)%
	Wholesale and retail electric sales(b)			34.35				32.68				5.1	%
	Total — excluding the trading portfolio			33.34				32.66				2.1	%
Average supply cost(c) — excluding the trading portfolio			$	20.06			$	21.13				(5.1	)%
Average margin — excluding the trading portfolio			$	13.28			$	11.53				15.2	%

---

(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 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.

     The changes in Generation’s operating revenues for the three months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Retail gas revenue		$	84
Wholesale and retail electric sales			(39	)
Electric revenue from affiliates			(31	)
Other			48
Increase in operating revenues		$	62

      Retail Gas Revenue. Retail gas revenue increased $84 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

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

		Variance
Effects of EITF 03-11 adoption(a)		$	(238	)
Boston Generating			(43	)
Exelon Energy Company and AmerGen operations			104
Other operations			138
Decrease in wholesale and retail electric sales		$	(39	)

---

(a)		Does not include $1 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 resulted in less revenues from this entity compared to the same period in the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $104 million compared to the same period in the prior year.

      The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, and in the Mid-Atlantic region market prices were driven by higher oil and gas prices.

143

---

 

      Electric Sales to Affiliates. Revenue from sales to affiliates decreased primarily as a result of 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 June 30, 2003 was $44 million.

      The decrease in revenue from sales to affiliates was partially offset by $15 million in higher sales to Energy Delivery. The higher sales to Energy Delivery were primarily due to an overall increased usage per customer and favorable weather conditions.

      Other. Certain other revenues increased for the three months ended June 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:

		Three Months
		Ended June 30,
Supply Source (in GWhs)		2004				2003				Variance				% Change
Nuclear generation(a)			34,254				29,619				4,635				15.6	%
Purchases — non-trading portfolio(b)			11,904				19,344				(7,440	)			(38.5	)%
Fossil and hydro generation			4,951				5,355				(404	)			(7.5	)%
Total supply			51,109				54,318				(3,209	)			(5.9	)%

---

(a)		Excludes AmerGen for 2003. AmerGen generated 5,122 GWhs during the three months ended June 30, 2004.
(b)		Sales in 2004 do not include 6,185 GWhs that 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 3,731 GWhs in 2003.

     Generation’s supply mix changed as a result of the sale of Boston Generating in May 2004.

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

		Variance
Effects of the adoption of EITF 03-11		$	(239	)
Volume			92
Price			49
Boston Generating			(33	)
Midwest Generation			(25	)
AmerGen and Exelon Energy Company			(11	)
Sithe Energies, Inc.			62
Mark-to-market adjustments on hedging activity			11
Other			(29	)
Decrease in purchased power and fuel expense		$	(123	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $238 million and fuel expense of $1 million.

      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 is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation below for further information).

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

144

---

 

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

      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, purchased power decreased $97 million. 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 $86 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results.

      Sithe Energies, Inc. 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.

      Hedging Activity. Mark-to-market gains on hedging activities were $21 million for the three months ended June 30, 2004 compared to gains of $32 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $6 million and hedging activities relating to other Generation operations in 2004 accounted for a gain of $15 million.

      Other. Other decreases in purchased power and fuel expense were primarily due to $21 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 and $10 million of nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

	Operating and Maintenance

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

		Variance
AmerGen and Exelon Energy Company		$	87
Sithe Energies, Inc.			22
Decommissioning accretion costs(a)			18
Boston Generating			13
Pension, payroll and benefit costs, primarily associated with The Exelon Way			(14	)
Other			46
Increase in operating and maintenance expense		$	172

---

(a)		Includes $10 million due to AmerGen asset retirement obligation accretion.

     The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen, Exelon Energy Company and Sithe in Generation’s consolidated results for 2004. The increase in operating and maintenance expenses attributable to Boston Generating was due to Mystic 8 and 9 and Fore River commencing commercial operation at the end of the second quarter of 2003 and in the third quarter of 2003, respectively, which more than offset the reduction in operating and maintenance expenses resulting from their sale in May 2004. Decommissioning accretion costs increased primarily due to the inclusion of AmerGen in this period compared to the prior year. The reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.

145

---

 

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

		Three Months
		Ended June 30,
		2004				2003
Nuclear fleet capacity factor(a)			96.1	%			94.0	%
Nuclear fleet production cost per MWh(a)		$	10.88			$	12.08
Average purchased power cost for wholesale operations per MWh(b)		$	47.13			$	41.36

---

(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 and lower nuclear production costs were primarily due to nine fewer planned refueling outage days, resulting in a $14 million decrease in planned outage costs for the three months ended June 30, 2004 as compared to the same period in 2003. There was one planned refueling outage that began in late March 2004 and was completed during the three months ended June 30, 2004, while there was one refueling outage that began and was completed during the three months ended June 30, 2003. The three months ended June 30, 2004 included seven unplanned outages compared to nine unplanned outages during the same period in 2003.

      In the three months ended June 30, 2004 as compared to the three months ended June 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 June 30, 2004 as compared to the same period in 2003 includes the impact of 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 as the assets were classified as held for sale during the period.

	Interest Expense

      The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December 2003 and interest expense related to Sithe long-term debt.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $20 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. 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.

146

---

 

	Other, Net

      The components of other, net for the three months ended June 30, 2004 as compared to the same period in the prior year, are as follows:

		Three Months
		Ended June 30,
Other, Net		2004				2003				Variance				% Change
Gain on sale of Boston Generating(a)			85				—				85				n.m.
Decommissioning trust funds(b)			29				32				(3	)			(9.4	)%
Decommissioning trust funds — AmerGen(b)			9				—				9				n.m.
Other income from Sithe			9				—				9				n.m.
Other			2				2				—				—
Total			134				34				100				n.m.

---

(a)	See Note 3 of the Combined Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating.

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

n.m. — not meaningful

	Effective Income Tax Rate

      The effective income tax rate was 38% for the three months ended June 30, 2004 compared to 39% 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. In addition, the rate increased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

147

---

 

Results of Operations

	Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

				Six Months Ended
				June 30,
				2004				2003				Variance				% Change
Operating revenues				$	3,900			$	3,765			$	135				3.6	%
Operating expenses
	Purchased power				1,081				1,642				(561	)			(34.2	)%
	Fuel				1,048				706				342				48.4	%
	Operating and maintenance				1,273				943				330				35.0	%
	Depreciation and amortization				124				91				33				36.3	%
	Taxes other than income				95				88				7				8.0	%
		Total operating expenses			3,621				3,470				151				4.4	%
Operating income					279				295				(16	)			(5.4	)%
Other income and deductions
	Interest expense				(77	)			(38	)			(39	)			(102.6	)%
	Equity in earnings (losses) of unconsolidated affiliates				(2	)			37				(39	)			(105.4	)%
	Other, net				183				(132	)			315				n.m.
		Total other income and deductions			104				(133	)			237				178.2	%
Income before income taxes, minority interest and cumulative effect of changes in accounting principles					383				162				221				136.4	%
Income taxes					146				71				75				105.6	%
Income before minority interest and cumulative effect of changes in accounting principles					237				91				146				160.4	%
Minority interest					11				(2	)			13				n.m.
Income before cumulative effect of changes in accounting principles					248				89				159				178.7	%
Cumulative effect of changes in accounting principles, net of income taxes					32				108				(76	)			(70.4	)%
Net income				$	280			$	197			$	83				42.1	%

---

n.m. — not meaningful

148

---

 

	Operating Revenues

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

		Six Months Ended
		June 30,
Revenue		2004				2003				Variance				% Change
Electric sales to affiliates(a)		$	1,706			$	1,842			$	(136	)			(7.4	)%
Wholesale and retail electric sales(b)			1,742				1,754				(12	)			(0.7	)%
Total electric energy sales revenue			3,448				3,596				(148	)			(4.1	)%
Retail gas sales			260				—				260				n.m.
Trading portfolio			(2	)			(2	)			—				—
Other revenue(c)			194				171				23				13.5	%
Total revenue		$	3,900			$	3,765			$	135				3.6	%

---

(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

		Six Months Ended
		June 30,
Sales (in GWhs)		2004				2003				Variance				% Change
Electric sales to affiliates(a)			53,597				57,463				(3,866	)			(6.7	)%
Wholesale and retail electric sales(b)			48,959				51,264				(2,305	)			(4.5	)%
Total sales			102,556				108,727				(6,171	)			(5.7	)%

---

(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 11,638 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 10,437 GWhs and 17,446 GWhs for the six months ended June 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.

149

---

 

      Generation’s average margin and other operating data for the six months ended June 30, 2004 and 2003 are as follows:

			Six Months Ended
			June 30,
($/MWh)			2004				2003				% Change
Average revenue
	Electric sales to affiliates(a)		$	31.83			$	32.06				(0.7	)%
	Wholesale and retail electric sales(b)			35.58				34.22				4.0	%
	Total — excluding the trading portfolio			33.62				33.07				1.7	%
Average supply cost(c) — excluding the trading portfolio			$	20.77			$	21.60				(3.8	)%
Average margin — excluding the trading portfolio			$	12.85			$	11.47				12.0	%

---

(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 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.

     The changes in Generation’s operating revenues for the six months ended June 30, 2004 compared to the same period in 2003 consisted of the following:

		Variance
Retail gas revenue		$	260
Electric sales to affiliates			(136	)
Wholesale and retail electric sales			(12	)
Other			23
Increase in operating revenues		$	135

      Retail Gas Revenue. Retail gas revenue increased as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

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

		Variance
Effects of EITF 03-11 adoption(a)		$	(444	)
Boston Generating			74
Exelon Energy Company and AmerGen operations			182
Other operations			176
Decrease in wholesale and retail electric sales		$	(12	)

---

(a)		Does not include $8 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 acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $182 million compared to the same period in the prior year.

      The other increase in wholesale and retail electric sales was primarily due to higher demand in the forward wholesale market and higher prices in the spot wholesale market. Market prices in the Midwest region were primarily driven by higher coal prices, while the Mid-Atlantic region market prices were driven primarily by higher oil and gas prices.

150

---

 

      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 six months ended June 30, 2003 was $108 million.

      The decrease in revenue from sales to affiliates included $40 million in lower sales to Energy Delivery. The lower sales to Energy Delivery was 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.

      Other. Certain other revenues increased for the six months ended June 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:

		Six Months Ended
		June 30,
Supply Source (in GWhs)		2004(c)				2003				Variance				% Change
Nuclear generation(a)			67,665				58,949				8,716				14.8	%
Purchases — non-trading portfolio(b)			23,595				39,373				(15,778	)			(40.1	)%
Fossil and hydroelectric generation			11,296				10,405				891				8.6	%
Total supply			102,556				108,727				(6,171	)			(5.7	)%

---

(a)		Excludes AmerGen for 2003. AmerGen generated 9,761 GWhs during the six months ended June 30, 2004.
(b)		Sales in 2004 do not include 11,638 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 PPAs with AmerGen, which represented 6,219 GWhs in 2003.

     Generation’s supply mix changed as a result of increased fossil generation due to Boston Generating’s Mystic units 8 and 9 and Fore River generating facilities becoming operational in the second and third quarter of 2003, which in total accounted for an increase of 2,688 GWhs offset by decreases in other fossil generating facilities.

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

		Variance
Effects of the adoption of EITF 03-11		$	(452	)
Volume			129
Price			(47	)
Midwest Generation			(48	)
AmerGen and Exelon Energy Company			101
Sithe Energies, Inc.			62
Boston Generating			75
Mark-to-market adjustments on hedging activity			19
Other			(58	)
Decrease in purchased power and fuel expense		$	(219	)

      Adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a decrease in purchased power of $444 million and fuel expense of $8 million.

151

---

 

      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 is partially offset by decreased purchased power from Midwest Generation (see Midwest Generation below for further information).

      Price. The decrease primarily reflects lower average fossil fuel costs of $47 million during the six months ended June 30, 2004 as compared to the same period in 2003. Natural gas, oil and coal prices all decreased during this period.

      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.

      AmerGen and Exelon Energy Company. As result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $160 million. 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 $261 million as fuel purchases made by Exelon Energy Company did not previously impact Generation’s results.

      Sithe Energies, Inc. 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.

      Boston Generating. The increase in fuel and purchased power expense for Boston Generating is due primarily to the Mystic 8 and 9 generating facilities which began commercial operations at the end of the second quarter of 2003, and the Fore River generating facilities which began commercial operations during the third quarter of 2003. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding Boston Generating. The increase was offset by a decrease of $13 million related to the effects of adopting EITF 03-11.

      Hedging Activity. Mark-to-market losses on hedging activities were $18 million for the six months ended June 30, 2004 compared to gains of $1 million for the same period of 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities for other Generation operations in 2004 accounted for a loss of $22 million.

      Other. Other decreases in purchased power and fuel were primarily due to $46 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, offset by $16 million of additional nuclear fuel amortization recorded in 2003 as a result of the replacement of underperforming fuel at the Quad Cities Station.

	Operating and Maintenance

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

		Variance
AmerGen and Exelon Energy Company(a)		$	197
Refueling outage costs			38
Boston Generating			33
Decommissioning accretion costs(b)			25
Sithe Energies, Inc.			22
Pension, payroll and benefit costs associated with The Exelon Way			(23	)
Other			38
Increase in operating and maintenance expense		$	330

152

---

 

---

(a)		Includes refueling outage expense of $24 million at AmerGen.
(b)		Includes $20 million due to AmerGen asset retirement obligation accretion.

     The increase in operating and maintenance expense is due primarily to the inclusion of AmerGen, Exelon Energy Company and Sithe in 2004. Also, operating and maintenance expenses increased at Boston Generating due to Mystic 8 and 9 and Fore River commencing commercial operations in the second and third quarters of 2003. Decommissioning accretion costs also increased primarily due to the inclusion of AmerGen in this period as compared to the prior year. A reduction in payroll-related costs associated with the implementation of the programs associated with The Exelon Way partially offset the other increases to operating and maintenance expense.

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

		Six Months Ended
		June 30,
		2004				2003
Nuclear fleet capacity factor(a)			93.3	%			94.2	%
Nuclear fleet production cost per MWh(a)		$	12.54			$	12.40
Average purchased power cost for wholesale operations per MWh(b)		$	45.81			$	41.68

---

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

     Lower nuclear capacity factors and increased nuclear production costs were primarily due to 55 additional planned refueling outage days, resulting in a $46 million increase in planned outage costs in the six months ended June 30, 2004 as compared to the same period in 2003. There were five planned outages during the six months ended June 30, 2004, compared to three planned outages during the same period in 2003. The six months ended June 30, 2004 included twelve unplanned outages compared to eleven unplanned outages during the same period in 2003. 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 six months ended June 30, 2004 as compared to the same period in 2003 was primarily attributable to the impact of 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 as the assets were classified as held for sale during the period.

	Interest Expense

      The increase in interest expense was primarily due to the issuance of $500 million of Senior Notes in December 2003 and interest expense related to Sithe long-term debt.

	Equity in Earnings (Losses) of Unconsolidated Affiliates

      The decrease in equity in earnings of unconsolidated affiliates was primarily due to a $37 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. 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.

153

---

 

	Other, Net

      The components of other, net for the six months ended June 30, 2004 as compared to the same period in the prior year, are as follows:

		Six Months
		Ended June 30,
Other, Net		2004				2003				Variance				% Change
Gain on sale of Boston Generating(a)			85				—				85				n.m.
Decommissioning trust funds(b)			60				63				(3	)			(4.8	)%
Decommissioning trust funds — AmerGen(b)			20				—				20				n.m.
Other income from Sithe			9				—				9				n.m.
Impairment of Investment in Sithe			—				(200	)			200				(100.0	)%
Other			9				5				4				80.0	%
Total			183				(132	)			315				n.m.

---

(a)		See Note 3 of the Combined Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating.
(b)		Includes investment income and realized gains/(losses)

n.m. — not meaningful

	Effective Income Tax Rate

      The effective income tax rate was 38% for the six months ended June 30, 2004 compared to 44% 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. In addition, the rate decreased due to the additional nuclear decommissioning investment income associated with AmerGen and its related taxes. 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 six months ended June 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 net income for the six months ended June 30, 2003 reflects income of $108 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.

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, repayments of maturing 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.

154

---

 

	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 six months ended June 30, 2004 and 2003 were $616 million and $539 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 six months ended June 30, 2004 and 2003 were affected by the following items:

	•	Receivables from Exelon Delivery under the PPA increased $31 million for the six months ended June 30, 2004, compared to a decrease of $157 million during the same period in 2003.
	•	Net cash received for collateral for the six months ended June 30, 2004 was $2 million, compared to $136 million paid during the same period in 2003.
	•	Discretionary contributions to Exelon’s defined benefit pension plans were $121 million for the six months ended June 30, 2004 compared to $98 million for the same period in 2003.

      Generation participates in Exelon’s defined benefit pension plans. Exelon expects to contribute up to approximately $419 million to its pension plans in 2004, including $11 million to satisfy IRS minimum funding requirements. Of the $419 million, $170 million is expected to be funded by Generation during 2004.

	Cash Flows from Investing Activities

      Cash flows used in investing activities were $438 million and $534 million for the six months ended June 30, 2004 and 2003, respectively. Generation’s capital expenditures for the six months ended June 30, 2004 and 2003 were $366 million and $424 million, respectively. Generation’s capital expenditures represent additions to nuclear fuel and additions and upgrades to existing facilities. Capital expenditures for the six months ended June 30, 2003 are stated net of proceeds from liquidated damages of $86 million. Generation estimates that it will spend approximately $972 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 Financing Activities

      Cash flows used in financing activities were $141 million for the six months ended June 30, 2004, compared to cash flows provided by financing activities of $11 million for the same period in 2003. The increase in cash flows used in financing activities was primarily a result of a net repayment of intercompany borrowings of $218 million during the six months ended June 30, 2004, compared to a $58 million net increase in intercompany borrowings during the same period in 2003 and a $64 million increase in distributions to Exelon during the six months ended June 30, 2004 as compared to the same period in 2003. This use of cash was partially offset by the issuance of $211 million of commercial paper during the six months ended June 30, 2004 and the partial repayment of the acquisition note payable to Sithe of $27 million during the six months ended June 30, 2004, compared a $210 million payment during the same period in 2003.

      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.

155

---

 

	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. Generation participates, 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 June 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 six months ended June 30, 2004, Generation paid $1.5 million in interest to the money pool.

      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 June 30, 2004, Generation had undistributed earnings of $773 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 June 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.

156

---

 

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, including forwards, futures, swaps, and options, with approved counterparties to hedge its anticipated exposures. Generation has an estimated 90% hedge ratio in 2004 for its energy marketing portfolio. This hedge ratio represents the percentage of Generation’s forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. Energy Delivery’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods the amount hedged declines to meet Generation’s commitment to Energy Delivery. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for Generation’s non-trading portfolio associated with a 10% reduction in the annual average around-the-clock market price of electricity is approximately a $19 million decrease in net income. This sensitivity assumes a 90% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

	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 six months ended June 30, 2004 was a loss $2 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

157

---

 

      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 earnings on a current basis.

      The following detailed presentation of the proprietary trading and non-trading marketing activities of Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. Generation does not consider its proprietary trading to be a significant activity of its business; however, Generation believes it is important to include these risk management disclosures.

      The following tables describe the drivers of Generation’s energy trading and marketing business and gross margin included in the income statement for the three and six months ended June 30, 2004 and 2003. Normal operations and hedging activities represent the marketing of electricity available from Generation’s owned or contracted generation, including generation used to serve Energy Delivery’s retail load, sold into the wholesale market. As the information in these tables highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).

			Three Months
			Ended June 30,
			2004				2003
Mark-to-market activities:
Unrealized mark-to-market gain/(loss)
	Origination unrealized gain/(loss) at inception		$	—			$	—
	Changes in fair value prior to settlements			115				108
	Changes in valuation techniques and assumptions			—				—
	Reclassification to realized at settlement of contracts			(125	)			(78	)
	Total change in unrealized fair value(a)			(10	)			30
Realized net settlement of transactions subject to mark-to-market				125				78
Total mark-to-market activities gross margin			$	115			$	108

158

---

 

			Three Months
			Ended June 30,
			2004				2003
Accrual activities:
Accrual activities revenue			$	1,132			$	1,107
Hedge gains reclassified from OCI				684				616
	Total revenue — accrual activities			1,816				1,723
Purchased power and fuel				200				388
Hedges of purchased power and fuel reclassified from OCI				808				705
	Total purchased power and fuel			1,008				1,093
	Total accrual activities gross margin			808				630
Total gross margin(b)			$	923			$	738

---

(a)		Includes $2 million of unrealized losses due to proprietary trading activity during the three months ended June 30, 2003.
(b)		Total gross margin represents revenue, net of purchased power and fuel expense.

			Six Months Ended
			June 30,
			2004				2003
Mark-to-market activities:
Unrealized mark-to-market gain/(loss)
	Origination unrealized gain/(loss) at inception		$	—			$	—
	Changes in fair value prior to settlements(a)			150				132
	Changes in valuation techniques and assumptions			—				—
	Reclassification to realized at settlement of contracts			(200	)			(135	)
	Total change in unrealized fair value(b)			(50	)			(3	)
Realized net settlement of transactions subject to mark-to-market				200				135
Total mark-to-market activities gross margin			$	150			$	132
Accrual activities:
Accrual activities revenue			$	2,527			$	2,459
Hedge gains reclassified from OCI				1,185				1,014
	Total revenue — accrual activities			3,712				3,473
Purchased power and fuel				657				980
Hedges of purchased power and fuel reclassified from OCI				1,434				1,208
	Total purchased power and fuel			2,091				2,188
	Total accrual activities gross margin			1,621				1,285
Total gross margin(c)			$	1,771			$	1,417

---

(a)		Includes hedge ineffectiveness of $1 million recorded in earnings.
(b)		Includes $1 million and $4 million of unrealized losses due to proprietary trading activity during the six months ended June 30, 2004 and 2003, respectively.
(c)		Total gross margin represents revenue, net of purchased power and fuel expense.

     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 June 30, 2004. It indicates the drivers behind changes in the

159

---

 

Total mark-to-market energy contract net assets at January 1, 2004		$	(216	)
Total change in fair value during 2004 of contracts recorded in earnings			148
Reclassification to realized at settlement of contracts recorded in earnings			(199	)
Reclassification to realized at settlement from OCI			248
Effective portion of changes in fair value — recorded in OCI			(535	)
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market			147
Total mark-to-market energy contract net assets (liabilities) at June 30, 2004		$	(407	)

      The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2004 and December 31, 2003:

			June 30,				December 31,
			2004				2003
Current assets			$	433			$	322
Noncurrent assets				390				100
	Total mark-to-market energy contract assets			823				422
Current liabilities(a)				(805	)			(505	)
Noncurrent liabilities				(425	)			(133	)
	Total mark-to-market energy contract liabilities			(1,230	)			(638	)
Total mark-to-market energy contract net assets (liabilities)			$	(407	)		$	(216	)

---

(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 June 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.

160

---

 

      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
Normal operations, qualifying cash-flow hedge contracts(a):
	Actively quoted prices			$	2			$	1			$	—			$	—			$	—			$	3
	Prices provided by other external sources				(227	)			(217	)			(30	)			(6	)			—				(480	)
		Total		$	(225	)		$	(216	)		$	(30	)		$	(6	)		$	—			$	(477	)
Normal operations, other derivative contracts(b):
	Actively quoted prices			$	32			$	8			$	(1	)		$	—			$	—			$	39
	Prices provided by other external sources				(59	)			11				5				—				—				(43	)
	Prices based on model or other valuation methods				9				(13	)			13				9				56				74
		Total		$	(18	)		$	6			$	17			$	9			$	56			$	70

---

(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.

     The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of June 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 six months ended June 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				Cash Flow
		Hedging Activities				Other Hedges(a)				Hedges
Accumulated OCI derivative loss at January 1, 2004		$	(133	)		$	(13	)		$	(146	)
Changes in fair value			(310	)			—				(310	)
Reclassifications from OCI to net income			151				12				163
Exelon Energy Company opening balance			2				—				2
Sithe			—				(11	)			(11	)
Accumulated OCI derivative loss at June 30, 2004		$	(290	)		$	(12	)		$	(302	)

---

(a)		Includes interest rate hedges at Generation.

161

---

 

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.

      The following tables provide information on Generation’s wholesale credit exposure, net of collateral, as of June 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
			Before Credit				Credit				Net				Greater than 10%				Greater than 10%
Rating(a)			Collateral				Collateral				Exposure				of Net Exposure				of Net Exposure
Investment grade			$	138			$	17			$	121				3			$	71
Split rating				—				—				—				—				—
Non-investment grade				77				10				67				1				55
No external ratings
	Internally rated — investment grade			13				2				11				—				—
	Internally rated — non-investment grade			1				—				1				—				—
Total			$	229			$	29			$	200				4			$	126

---

(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)			2 Years				2-5 Years				5 Years				Collateral
Investment grade			$	128			$	10			$	—			$	138
Split rating				—				—				—				—
Non-investment grade				75				2				—				77
No external ratings
	Internally rated — investment grade			13				—				—				13
	Internally rated — non-investment grade			1				—				—				1
Total			$	217			$	12			$	—			$	229

---

(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 June 30, 2004, Generation has credit risk

162

---

 

      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 tolling agreement associated with the Independence plant. 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. Additionally, 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. In February 2004, Dynegy announced an agreement to sell Illinois Power to a third party, which, upon closing of the transaction, would reduce 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, California 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, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation’s financial condition, results of operations or net cash flows.

Interest Rate Risk

	ComEd

      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

163

---

 

      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 June 30, 2004, these interest-rate swaps, designated as fair-value hedges, had an aggregate fair market value of $1 million based on the present value difference between the contract and market rates at June 30, 2004. If these derivative instruments had been terminated at June 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 June 30, 2004 is estimated to be $8 million in ComEd’s favor. If the derivative instrument had been terminated at June 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 June 30, 2004 is estimated to be $7 million in the counterparties’ favor. If the derivative instrument had been terminated at June 30, 2004, this estimated fair value represents the amount ComEd would pay the counterparties.

      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

      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 June 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.

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 June 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 $308 million reduction in the fair value of the trust assets.

164

---

 

Item 4.	Controls and Procedures

      During the second 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, summarization 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 June 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.

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 for a discussion of legal proceeding developments.

165

---

 

Item 2.	Changes in 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
January 1 — January 31, 2004			157,785			$	32.57				—				—
February 1 — February 29, 2004			14,491				33.36				—				—
March 1 — March 31, 2004			18,657				33.92				—				—
April 1 — April 30, 2004			—				—				—				(a	)
May 1 — May 31, 2004			1,809,817				31.87				1,809,000				(a	)
June 1 — June 30, 2004			523,966				33.05				518,100				(a	)
Total			2,524,716				32.18				2,327,100				(a	)

---

(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.

Item 4.	Submission of Matters to a Vote of Security Holders

Exelon

      Exelon held its 2004 Annual Meeting of Shareholders on April 27, 2004.

      Proposal 1 was the election of four Class I directors to serve three-year terms expiring in 2007. The following directors were elected:

		Votes For				Votes Withheld
Nicholas DeBenedictis			259,939,186				10,816,919
G. Fred DiBona, Jr.			264,314,416				6,441,689
Sue L. Gin			262,458,220				8,297,885
Edgar D. Jannotta			265,237,110				5,518,995

      Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2004. The shareholders approved the proposal with 262,663,675 votes cast for, 784,220 votes cast against and 2,308,210 votes abstaining.

      Proposal 3 was the approval of the Exelon Corporation Annual Incentive Plan (the Plan) for Senior Executives effective January 1, 2004, as described in the proxy statement. The shareholders approved the Plan with 246,985,526 votes cast for, 18,996,405 votes cast against and 4,804,174 votes abstaining.

166

---

 

PECO

      PECO held its 2004 Annual Meeting of Shareholders on May 27, 2004. At the PECO annual meeting, the only proposal was the election of two Class III directors to serve three-year terms expiring in 2007. Denis P. O’Brien and Robert S. Shapard were elected with 170,478,507 votes cast for each director, no votes cast against and no votes abstaining.

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 Discuss 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, and a majority of PECO employees eligible to vote voted in favor of representation by the IBEW. The NLRB will certify the election on July 29, 2004.

	Jointly Owned Electric Utility Plant (Generation)

      On January 28, 2004, the NRC issued a letter requesting PSE&G 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. PSE&G 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 need to be addressed. At an NRC public meeting on June 16, 2004, PSE&G 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.

      In June 2001, the NJDEP issued a renewed NPDES 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 FWPCA 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 PSE&G 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. PSE&G 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 require 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.

      (b) Exelon, ComEd, PECO and Generation

      None.

167

---

 

Item 6.	Exhibits and Reports on Form 8-K

      (a) Exhibits:

3-1		—		Amendment to Articles of Incorporation for Exelon Corporation effective as of April 19, 2004.
10-1		—		Amended and Restated Power Purchase Agreement between Exelon Generation Company, LLC and Commonwealth Edison Company as of April 30, 2004.
10-2		—		$1,000,000,000 Five Year Credit Agreement dated as of July 16, 2004 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders.
10-3		—		First Amendment dated as of July 16, 2004 to Three Year Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Exelon Generation Company, LLC, various financial institutions and Bank One, NA, as administrative agent.

      Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 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 Oliver D. Kingsley Jr. 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 June 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 Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
32-8		—		Filed by J. Barry Mitchell for Exelon Generation Company, LLC

168

---

 

      (b) Reports on Form 8-K:

      Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the three months ended June 30, 2004 regarding the following items:

Date of Earliest
Event Reported				Description of Item Reported
	April 8, 2004			“ITEM 5. OTHER EVENTS” filed for Exelon announcing the record and distribution dates for the previously announced 2-for-1 stock split.
	April 16, 2004			“ITEM 5. OTHER EVENTS” and “ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS” filed for PECO regarding an Underwriting Agreement entered into due to the issuance of First and Refunding Mortgage Bonds.
	April 27, 2004			“ITEM 5. OTHER EVENTS” filed for Exelon announcing the declaration of a quarterly dividend and an equity plan share repurchase program.
	May 10, 2004			“ITEM 5. OTHER EVENTS” filed for Exelon and Generation regarding the FERC’s authorization of the transfer of ownership of BG to the lenders’ special purpose entity.
	May 25, 2004			“ITEM 5. OTHER EVENTS” filed for Exelon and Generation regarding the completion of the transfer of ownership of Boston Generating to the lenders’ special purpose entity.
	May 25, 2004			“ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS” AND “ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS” filed for Exelon and Generation including pro forma financial information related to the transfer of ownership of Boston Generating.

169

---

 

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)

July 28, 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

July 28, 2004

170

---

 

      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

July 28, 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/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.				Chief Executive Officer and 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)

July 28, 2004

171

 

---

 

---

 

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

---

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 June 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.