Commonwealth Edison 10Q 2006 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


	þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Quarterly Period Ended June 30, 2006
or
	o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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

1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street — 37^th Floor P.O. Box 805379 Chicago, Illinois60680-5379 (312) 394-7398	23-2990190
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania19101-8699 (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, 2006 was:


Exelon Corporation Common Stock, without par value		669,489,140
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,519
PECO Energy Company Common Stock, without par value		170,478,507
Exelon Generation Company, LLC		not applicable

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

Large Accelerated Filer

Accelerated Filer

Non-accelerated Filer

Exelon Corporation

Commonwealth Edison Company

PECO Energy Company

Exelon Generation Company, LLC

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

TABLE OF CONTENTS


		Page No.

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

PART I.	FINANCIAL INFORMATION		4
ITEM 1.	FINANCIAL STATEMENTS		4
	Exelon Corporation
	Consolidated Statements of Income and Comprehensive Income		5
	Consolidated Statements of Cash Flows		6
	Consolidated Balance Sheets		7
	Consolidated Statement of Changes in Shareholders’ Equity		9
	Commonwealth Edison Company
	Consolidated Statements of Income and Comprehensive Income		10
	Consolidated Statements of Cash Flows		11
	Consolidated Balance Sheets		12
	Consolidated Statement of Changes in Shareholders’ Equity		14
	PECO Energy Company
	Consolidated Statements of Income and Comprehensive Income		15
	Consolidated Statements of Cash Flows		16
	Consolidated Balance Sheets		17
	Consolidated Statement of Changes in Shareholders’ Equity		19
	Exelon Generation Company, LLC
	Consolidated Statements of Income and Comprehensive Income		20
	Consolidated Statements of Cash Flows		21
	Consolidated Balance Sheets		22
	Consolidated Statement of Changes in Member’s Equity		24
	Combined Notes to Consolidated Financial Statements		25
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		77
	Exelon Corporation		77
	Commonwealth Edison Company		127
	PECO Energy Company		128
	Exelon Generation Company, LLC		130
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		132
ITEM 4.	CONTROLS AND PROCEDURES		138

PART II.	OTHER INFORMATION		138
ITEM 1.	LEGAL PROCEEDINGS		138
ITEM 1A.	RISK FACTORS		138
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		139
ITEM 4.	SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS		140
ITEM 5.	OTHER INFORMATION		140


		Page No.

ITEM 6.	EXHIBITS		141
SIGNATURES			142
	Exelon Corporation		142
	Commonwealth Edison Company		142
	PECO Energy Company		143
	Exelon Generation Company, LLC		143
CERTIFICATION EXHIBITS			144
	Exelon Corporation		144,152
	Commonwealth Edison Company		146,154
	PECO Energy Company		148,156
	Exelon Generation Company, LLC		150,158
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification

FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include (a) those factors discussed in the following sections of the Registrants’ 2005 Annual Report onForm 10-K: ITEM 1A. Risk Factors, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 20, ComEd — Note 17, PECO — Note 15 and Generation — Note 17; and (b) other factors discussed herein and in other filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC atwww.sec.gov and Exelon’s website and the other Registrant’s web sites atwww.exeloncorp.com. Information contained on Exelon’s web site shall not be deemed incorporated into, or to be a part of, this Report.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions, except per share data)	2006			2005			2006			2005

Operating revenues	$	3,697		$	3,484		$	7,559		$	7,045
Operating expenses
Purchased power		571			663			1,096			1,232
Fuel		502			493			1,438			1,115
Operating and maintenance		881			929			1,906			1,877
Depreciation and amortization		371			325			735			644
Taxes other than income		170			177			364			349

Total operating expenses		2,495			2,587			5,539			5,217

Operating income		1,202			897			2,020			1,828

Other income and deductions
Interest expense		(154	)		(129	)		(306	)		(235	)
Interest expense to affiliates		(68	)		(81	)		(139	)		(164	)
Distributions on preferred securities of subsidiaries		(1	)		(1	)		(2	)		(2	)
Equity in losses of unconsolidated affiliates		(22	)		(32	)		(61	)		(68	)
Other, net		47			69			93			99

Total other income and deductions		(198	)		(174	)		(415	)		(370	)

Income from continuing operations before income taxes		1,004			723			1,605			1,458
Income taxes		363			207			564			435

Income from continuing operations		641			516			1,041			1,023

Discontinued operations
Loss from discontinued operations (net of taxes of $0 and $(3) for the three and six months ended June 30, 2005, respectively)		—			(1	)		—			(3	)
Gain (loss) on disposal of discontinued operations (net of taxes of $2, $(1), $2 and $4 for the three and six months ended June 30, 2006 and 2005, respectively)		3			(1	)		3			15

Income (loss) from discontinued operations		3			(2	)		3			12

Net income		644			514			1,044			1,035

Other comprehensive income (loss), net of income taxes
Minimum pension liability		—			—			—			2
Change in unrealized gain (loss) on cash-flow hedges		140			(31	)		232			(133	)
Unrealized gain (loss) on marketable securities		(13	)		(9	)		15			(24	)

Other comprehensive income (loss)		127			(40	)		247			(155	)

Comprehensive income	$	771		$	474		$	1,291		$	880

Average shares of common stock outstanding:
Basic		670			670			669			669
Diluted		676			677			675			676

Earnings per average common share — basic:
Income from continuing operations	$	0.96		$	0.77		$	1.56		$	1.53
Income from discontinued operations		—			—			—			0.02

Net income	$	0.96		$	0.77		$	1.56		$	1.55

Earnings per average common share — diluted:
Income from continuing operations	$	0.95		$	0.76		$	1.55		$	1.51
Income from discontinued operations		—			—			—			0.02

Net income	$	0.95		$	0.76		$	1.55		$	1.53

Dividends per common share	$	0.40		$	0.40		$	0.80		$	0.80

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended June 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	1,044		$	1,035
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		1,060			961
Deferred income taxes and amortization of investment tax credits		(81	)		528
Provision for uncollectible accounts		42			22
Equity in losses of unconsolidated affiliates		61			68
Gain on sales of investments and wholly owned subsidiaries		(2	)		(17	)
Net realized (gains) losses on nuclear decommissioning trust funds		11			(55	)
Other decommissioning-related activities		(149	)		13
Impairment charges		117			—
Other non-cash operating activities		32			27
Changes in assets and liabilities
Accounts receivable		230			53
Inventories		11			26
Other current assets		(136	)		(136	)
Accounts payable, accrued expenses and other current liabilities		(406	)		(211	)
Counterparty collateral asset		178			(20	)
Counterparty collateral liability		5			7
Income taxes		300			24
Net realized and unrealizedmark-to-market and hedging transactions		(69	)		(74	)
Pension and non-pension postretirement benefits		99			(1,927	)
Other noncurrent assets and liabilities		(159	)		(38	)

Net cash flows provided by operating activities		2,188			286

Cash flows from investing activities
Capital expenditures		(1,156	)		(1,007	)
Proceeds from nuclear decommissioning trust fund sales		2,554			2,149
Investment in nuclear decommissioning trust funds		(2,706	)		(2,256	)
Acquisitions of businesses, net of cash acquired		—			(97	)
Proceeds from sales of investments and wholly owned subsidiaries, net of $32 of cash sold during the six months ended June 30, 2005		1			103
Investments in synthetic fuel-producing facilities		(53	)		(56	)
Change in restricted cash		1			23
Other investing activities		(1	)		(2	)

Net cash flows used in investing activities		(1,360	)		(1,143	)

Cash flows from financing activities
Issuance of long-term debt		326			1,788
Retirement of long-term debt		(34	)		(185	)
Retirement of long-term debt to financing affiliates		(422	)		(397	)
Issuance of short-term debt		—			2,500
Retirement of short-term debt		—			(2,200	)
Change in other short-term debt		(106	)		(161	)
Dividends paid on common stock		(535	)		(535	)
Proceeds from employee stock plans		107			156
Purchase of treasury stock		(53	)		(8	)
Other financing activities		31			(55	)

Net cash flows provided by (used in) financing activities		(686	)		903

Increase in cash and cash equivalents		142			46
Cash and cash equivalents at beginning of period		140			499

Cash and cash equivalents at end of period	$	282		$	545

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


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

ASSETS
Current assets
Cash and cash equivalents	$	282	$	140
Restricted cash and investments		48		49
Accounts receivable, net
Customer		1,609		1,858
Other		265		337
Mark-to-market derivative assets		737		916
Inventories, at average cost
Fossil fuel		282		311
Materials and supplies		381		351
Deferred income taxes		114		80
Other		540		595

Total current assets		4,258		4,637

Property, plant and equipment, net		22,122		21,981
Deferred debits and other assets
Regulatory assets		4,093		4,386
Nuclear decommissioning trust funds		5,809		5,585
Investments		819		813
Goodwill		3,476		3,475
Mark-to-market derivative assets		586		371
Prepaid pension asset		374		377
Other		753		824

Total deferred debits and other assets		15,910		15,831

Total assets	$	42,290	$	42,449

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


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

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Commercial paper and notes payable	$	1,184		$	1,290
Long-term debt due within one year		554			407
Long-term debt to ComEd Transitional Funding Trust and PECO Energy
Transition Trust due within one year		577			507
Accounts payable		1,195			1,467
Mark-to-market derivative liabilities		885			1,282
Accrued expenses		1,070			1,005
Other		838			605

Total current liabilities		6,303			6,563

Long-term debt		7,904			7,759
Long-term debt to ComEd Transitional Funding Trust and PECO
Energy Transition Trust		2,963			3,456
Long-term debt to other financing trusts		545			545
Deferred credits and other liabilities
Deferred income taxes		4,957			4,816
Unamortized investment tax credits		256			262
Asset retirement obligations		3,676			4,157
Pension obligations		292			268
Non-pension postretirement benefit obligations		1,086			1,014
Spent nuclear fuel obligation		926			906
Regulatory liabilities		2,293			2,170
Mark-to-market derivative liabilities		504			522
Other		763			798

Total deferred credits and other liabilities		14,753			14,913

Total liabilities		32,468			33,236

Commitments and contingencies
Minority interest of consolidated subsidiaries		—			1
Preferred securities of subsidiaries		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 669.5 and 666.4 shares outstanding at June 30, 2006 and December 31, 2005, respectively)		8,166			7,987
Treasury stock, at cost (10.4 and 9.4 shares held at June 30, 2006 and December 31, 2005, respectively)		(497	)		(444	)
Retained earnings		3,443			3,206
Accumulated other comprehensive loss		(1,377	)		(1,624	)

Total shareholders’ equity		9,735			9,125

Total liabilities and shareholders’ equity	$	42,290		$	42,449

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


												Accumulated
			��									Other			Total
(Dollars in millions,	Issued			Common		Treasury			Retained			Comprehensive			Shareholders’
shares in thousands)	Shares			Stock		Stock			Earnings			Loss			Equity

Balance, December 31, 2005		675.8		$	7,987	$	(444	)	$	3,206		$	(1,624	)	$	9,125
Net income		—			—		—			1,044			—			1,044
Long-term incentive plan activity		4.1			179		—			—			—			179
Common stock purchases		—			—		(53	)		—			—			(53	)
Common stock dividends declared		—			—		—			(807	)		—			(807	)
Other comprehensive income, net of income taxes of $175		—			—		—			—			247			247

Balance, June 30, 2006		679.9		$	8,166	$	(497	)	$	3,443		$	(1,377	)	$	9,735

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,450		$	1,485		$	2,874		$	2,869
Operating revenues from affiliates		3			3			6			6

Total operating revenues		1,453			1,488			2,880			2,875

Operating expenses
Purchased power		81			88			172			156
Purchased power from affiliate		685			770			1,456			1,523
Operating and maintenance		165			158			329			316
Operating and maintenance from affiliates		53			44			105			88
Depreciation and amortization		106			101			205			198
Taxes other than income		71			73			152			151

Total operating expenses		1,161			1,234			2,419			2,432

Operating income		292			254			461			443

Other income and deductions
Interest expense		(58	)		(53	)		(114	)		(102	)
Interest expense to affiliates		(19	)		(24	)		(39	)		(49	)
Equity in losses of unconsolidated affiliates		(3	)		(4	)		(5	)		(8	)
Interest income from affiliates		—			1			—			3
Other, net		1			6			1			10

Total other income and deductions		(79	)		(74	)		(157	)		(146	)

Income before income taxes		213			180			304			297
Income taxes		86			71			123			118

Net income		127			109			181			179

Other comprehensive loss, net of income taxes
Change in unrealized loss on cash-flow hedges		—			(19	)		—			(21	)

Other comprehensive loss		—			(19	)		—			(21	)

Comprehensive income	$	127		$	90		$	181		$	158

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended June 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	181		$	179
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities:
Depreciation, amortization and accretion		205			198
Deferred income taxes and amortization of investment tax credits		(25	)		230
Provision for uncollectible accounts		11			12
Equity in losses of unconsolidated affiliates		5			8
Other non-cash operating activities		18			23
Changes in assets and liabilities
Accounts receivable		24			(100	)
Inventories		(8	)		1
Other current assets		(10	)		(14	)
Accounts payable, accrued expenses and other current liabilities		(3	)		(27	)
Changes in receivables and payables to affiliates		33			137
Income taxes		100			3
Net realized and unrealizedmark-to-market and hedging transactions		7			—
Pension and non-pension postretirement benefits		34			(767	)
Other noncurrent assets and liabilities		3			(11	)

Net cash flows provided by (used in) operating activities		575			(128	)

Cash flows from investing activities
Capital expenditures		(465	)		(391	)
Changes in Exelon intercompany money pool contributions		—			287
Change in restricted cash		(1	)		(1	)
Other investing activities		5			1

Net cash flows used in investing activities		(461	)		(104	)

Cash flows from financing activities
Changes in short-term debt		(120	)		—
Issuance of long-term debt		320			91
Retirement of long-term debt		(1	)		(146	)
Retirement of Exelon intercompany money pool borrowings		(140	)		—
Retirement of long-term debt to ComEd Transitional Funding Trust		(174	)		(190	)
Dividends paid on common stock		—			(245	)
Contributions from parent		—			834
Other financing activities		(3	)		(5	)

Net cash flows provided by (used in) financing activities		(118	)		339

Increase (decrease) in cash and cash equivalents		(4	)		107
Cash and cash equivalents at beginning of period		38			30

Cash and cash equivalents at end of period	$	34		$	137

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


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

ASSETS
Current assets
Cash and cash equivalents	$	34	$	38
Restricted cash		1		—
Accounts receivable, net
Customer		747		806
Other		39		46
Inventories, at average cost		58		50
Deferred income taxes		20		13
Receivables from affiliates		16		37
Other		44		34

Total current assets		959		1,024

Property, plant and equipment, net		10,194		9,906
Deferred debits and other assets
Investments		41		41
Investments in affiliates		27		34
Goodwill		3,476		3,475
Receivables from affiliates		1,529		1,447
Prepaid pension asset		926		938
Other		347		346

Total deferred debits and other assets		6,346		6,281

Total assets	$	17,499	$	17,211

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


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

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	473		$	328
Long-term debt to ComEd Transitional Funding Trust due within one year		303			307
Accounts payable		192			223
Accrued expenses		512			417
Payables to affiliates		291			278
Commercial paper		339			459
Borrowing from Exelon intercompany money pool		—			140
Customer deposits		115			110
Other		56			46

Total current liabilities		2,281			2,308

Long-term debt		2,674			2,500
Long-term debt to ComEd Transitional Funding Trust		510			680
Long-term debt to other financing trusts		361			361
Deferred credits and other liabilities
Deferred income taxes		2,131			2,147
Unamortized investment tax credits		42			43
Asset retirement obligations		155			151
Non-pension postretirement benefit obligations		197			175
Regulatory liabilities		2,293			2,170
Other		278			280

Total deferred credits and other liabilities		5,096			4,966

Total liabilities		10,922			10,815

Commitments and contingencies
Shareholders’ equity
Common stock		1,588			1,588
Other paid-in capital		4,890			4,890
Retained earnings (deficit)		100			(81	)
Accumulated other comprehensive loss		(1	)		(1	)

Total shareholders’ equity		6,577			6,396

Total liabilities and shareholders’ equity	$	17,499		$	17,211

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


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

Balance, December 31, 2005	$	1,588	$	4,890	$	(1,180	)	$	1,099	$	(1	)	$	6,396
Net income		—		—		181			—		—			181
Appropriation of Retained Earnings for future dividends		—		—		(181	)		181		—			—

Balance, June 30, 2006	$	1,588	$	4,890	$	(1,180	)	$	1,280	$	(1	)	$	6,577

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,144		$	1,040		$	2,546		$	2,331
Operating revenues from affiliates		4			4			8			8

Total operating revenues		1,148			1,044			2,554			2,339

Operating expenses
Purchased power		72			58			142			109
Purchased power from affiliate		429			379			845			760
Fuel		76			66			402			331
Operating and maintenance		109			91			225			200
Operating and maintenance from affiliates		32			28			64			53
Depreciation and amortization		172			137			343			273
Taxes other than income		53			60			117			115

Total operating expenses		943			819			2,138			1,841

Operating income		205			225			416			498

Other income and deductions
Interest expense		(18	)		(13	)		(35	)		(26	)
Interest expense to affiliates		(49	)		(57	)		(101	)		(116	)
Equity in losses of unconsolidated affiliates		(2	)		(4	)		(6	)		(8	)
Other, net		2			6			5			9

Total other income and deductions		(67	)		(68	)		(137	)		(141	)

Income before income taxes		138			157			279			357
Income taxes		45			47			93			118

Net income		93			110			186			239
Preferred stock dividends		1			1			2			2

Net income on common stock	$	92		$	109		$	184		$	237

Comprehensive income, net of income taxes
Net income	$	93		$	110		$	186		$	239

Other comprehensive loss, net of income taxes
Change in net unrealized loss on cash-flow hedges		(1	)		(2	)		(1	)		(2	)

Other comprehensive loss		(1	)		(2	)		(1	)		(2	)

Comprehensive income	$	92		$	108		$	185		$	237

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended June 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	186		$	239
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		343			273
Deferred income taxes and amortization of investment tax credits		(138	)		(60	)
Provision for uncollectible accounts		31			11
Equity in losses of unconsolidated affiliates		6			8
Other non-cash operating activities		9			(4	)
Changes in assets and liabilities
Accounts receivable		73			43
Inventories		9			23
Deferred/over-recovered energy costs		61			18
Prepaid utility taxes		(81	)		(99	)
Other current assets		(3	)		—
Accounts payable, accrued expenses and other current liabilities		(123	)		(79	)
Change in receivables and payables to affiliates, net		39			36
Income taxes		142			27
Pension and non-pension postretirement benefits		5			(144	)
Other noncurrent assets and liabilities		3			9

Net cash flows provided by operating activities		562			301

Cash flows from investing activities
Capital expenditures		(164	)		(126	)
Changes in Exelon intercompany money pool contributions		8			34
Change in restricted cash		(1	)		28
Other investing activities		—			6

Net cash flows used in investing activities		(157	)		(58	)

Cash flows from financing activities
Issuance of long-term debt		6			—
Retirement of long-term debt		—			(8	)
Retirement of long-term debt to PECO Energy Transition Trust		(248	)		(207	)
Change in short-term debt		7			—
Dividends paid on common and preferred stock		(253	)		(233	)
Contributions from parent		71			180

Net cash flows used in financing activities		(417	)		(268	)

Decrease in cash and cash equivalents		(12	)		(25	)
Cash and cash equivalents at beginning of period		37			74

Cash and cash equivalents at end of period	$	25		$	49

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


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

ASSETS
Current assets
Cash and cash equivalents	$	25	$	37
Restricted cash		3		2
Accounts receivable, net
Customer		350		454
Other		21		57
Affiliate		—		13
Inventories, at average cost
Gas		142		151
Materials and supplies		11		11
Contributions to Exelon intercompany money pool		—		8
Deferred income taxes		34		7
Deferred energy costs		—		39
Prepaid utility taxes		81		—
Other		19		16

Total current assets		686		795

Property, plant and equipment, net		4,552		4,471
Deferred debits and other assets
Regulatory assets		4,093		4,386
Investments		22		22
Investment in affiliates		68		73
Receivable from affiliate		100		68
Prepaid pension asset		198		195
Other		4		8

Total deferred debits and other assets		4,485		4,752

Total assets	$	9,723	$	10,018

See the Combined Notes to Consolidated Financial Statements

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


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

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Commercial paper	$	227		$	220
Long-term debt to PECO Energy Transition Trust due within one year		274			199
Accounts payable		94			182
Accrued expenses		169			92
Payables to affiliates		204			178
Customer deposits		57			54
Over-recovered energy costs		22			—
Other		5			11

Total current liabilities		1,052			936

Long-term debt		1,189			1,183
Long-term debt to PECO Energy Transition Trust		2,453			2,776
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes		2,674			2,781
Unamortized investment tax credits		16			17
Asset retirement obligations		21			20
Non-pension postretirement benefit obligations		286			278
Other		141			139

Total deferred credits and other liabilities		3,138			3,235

Total liabilities		8,016			8,314

Commitments and contingencies
Shareholders’ equity
Common stock		2,193			2,193
Preferred stock		87			87
Receivable from parent		(1,161	)		(1,232	)
Retained earnings		582			649
Accumulated other comprehensive income		6			7

Total shareholders’ equity		1,707			1,704

Total liabilities and shareholders’ equity	$	9,723		$	10,018

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


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

Balance, December 31, 2005	$	2,193	$	87	$	(1,232	)	$	649		$	7		$	1,704
Net income		—		—		—			186			—			186
Common stock dividends		—		—		—			(251	)		—			(251	)
Preferred stock dividends		—		—		—			(2	)		—			(2	)
Repayment of receivable from parent		—		—		71			—			—			71
Other comprehensive loss, net of income taxes of $(1)		—		—		—			—			(1	)		(1	)

Balance, June 30, 2006	$	2,193	$	87	$	(1,161	)	$	582		$	6		$	1,707

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months						Six Months
	Ended June 30,						Ended June 30,
(In millions)	2006			2005			2006			2005

Operating revenues
Operating revenues	$	1,100		$	955		$	2,132		$	1,840
Operating revenues from affiliates		1,114			1,150			2,302			2,285

Total operating revenues		2,214			2,105			4,434			4,125

Operating expenses
Purchased power		418			517			781			967
Fuel		425			428			1,036			786
Operating and maintenance		362			536			955			1,077
Operating and maintenance from affiliates		78			66			153			134
Depreciation and amortization		72			63			139			125
Taxes other than income		41			39			84			74

Total operating expenses		1,396			1,649			3,148			3,163

Operating income		818			456			1,286			962

Other income and deductions
Interest expense		(40	)		(29	)		(81	)		(56	)
Interest expense to affiliates		—			—			(1	)		(2	)
Equity in earnings (losses) of unconsolidated affiliates		(1	)		4			(5	)		4
Other, net		14			51			20			69

Total other income and deductions		(27	)		26			(67	)		15

Income from continuing operations before income taxes		791			482			1,219			977
Income taxes		294			185			454			376

Income from continuing operations		497			297			765			601

Discontinued operations
Loss from discontinued operations (net of taxes of $0 and $(1) for the three and six months ended June 30, 2005, respectively)		—			—			—			—
Gain (loss) on disposal of discontinued operations (net of taxes of $2, $(1), $2 and $4 for the three and six months ended June 30, 2006 and 2005, respectively)		3			(1	)		3			15

Income (loss) from discontinued operations		3			(1	)		3			15

Net income		500			296			768			616

Other comprehensive income (loss), net of income taxes
Change in unrealized gain (loss) on cash-flow hedges		141			39			232			(85	)
Unrealized gain (loss) on marketable securities		(13	)		(9	)		15			(24	)
Foreign currency translation adjustment		—			(1	)		—			(1	)

Other comprehensive income (loss)		128			29			247			(110	)

Comprehensive income	$	628		$	325		$	1,015		$	506

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six
	Months Ended
	June 30,
(In millions)	2006			2005

Cash flows from operating activities
Net income	$	768		$	616
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		464			440
Deferred income taxes and amortization of investment tax credits		81			337
Equity in losses (earnings) of unconsolidated affiliates		5			(4	)
Gain on sale of investments		(2	)		(19	)
Net realized (gains) losses on nuclear decommissioning trust funds		11			(55	)
Other decommissioning-related activities		(149	)		13
Other non-cash operating activities		20			17
Changes in assets and liabilities
Accounts receivable		79			61
Receivables and payables to affiliates, net		11			(181	)
Inventories		10			3
Other current assets		(70	)		(25	)
Accounts payable, accrued expenses and other current liabilities		(237	)		(52	)
Counterparty collateral asset		178			(20	)
Counterparty collateral liability		5			7
Income taxes		38			174
Net realized and unrealizedmark-to-market and hedging transactions		(37	)		(57	)
Pension and non-pension postretirement benefits		45			(839	)
Other noncurrent assets and liabilities		(148	)		(36	)

Net cash flows provided by operating activities		1,072			380

Cash flows from investing activities
Capital expenditures		(512	)		(484	)
Proceeds from nuclear decommissioning trust fund sales		2,554			2,149
Investment in nuclear decommissioning trust funds		(2,706	)		(2,256	)
Acquisitions of businesses, net of cash acquired		—			(97	)
Proceeds from sales of wholly owned subsidiaries, net of $32 of cash sold during the six months ended June 30, 2005		—			103
Change in restricted cash		1			(2	)
Other investing activities		(3	)		(5	)

Net cash flows used in investing activities		(666	)		(592	)

Cash flows from financing activities
Retirement of long-term debt		—			(1	)
Changes in Exelon intercompany money pool borrowings		(92	)		(283	)
Distribution to member		(322	)		(319	)
Contribution from member		—			843
Other financing activities		(2	)		1

Net cash flows provided by (used in) financing activities		(416	)		241

Increase (decrease) in cash and cash equivalents		(10	)		29
Cash and cash equivalents at beginning of period		34			263

Cash and cash equivalents at end of period	$	24		$	292

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


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

ASSETS
Current assets
Cash and cash equivalents	$	24	$	34
Restricted cash and investments		2		3
Accounts receivable, net
Customer		506		585
Other		128		109
Mark-to-market derivative assets		699		916
Receivable from affiliates		428		411
Inventories, at average cost
Fossil fuel		140		160
Materials and supplies		312		290
Deferred income taxes		41		35
Prepayments and other current assets		380		497

Total current assets		2,660		3,040

Property, plant and equipment, net		7,241		7,464
Deferred debits and other assets
Nuclear decommissioning trust funds		5,809		5,585
Investments		128		120
Mark-to-market derivative assets		473		286
Prepaid pension asset		1,005		1,013
Other		286		216

Total deferred debits and other assets		7,701		7,220

Total assets	$	17,602	$	17,724

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


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

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Long-term debt due within one year	$	12	$	12
Accounts payable		813		954
Mark-to-market derivative liabilities		874		1,282
Payables to affiliates		36		4
Borrowings from Exelon intercompany money pool		—		92
Commercial paper		309		311
Accrued expenses		387		415
Other		283		330

Total current liabilities		2,714		3,400

Long-term debt		1,788		1,788
Deferred credits and other liabilities
Asset retirement obligations		3,500		3,986
Pension obligation		17		13
Non-pension postretirement benefit obligations		574		541
Spent nuclear fuel obligation		926		906
Deferred income taxes		931		663
Unamortized investment tax credits		198		202
Payables to affiliates		1,616		1,503
Mark-to-market derivative liabilities		420		460
Other		244		280

Total deferred credits and other liabilities		8,426		8,554

Total liabilities		12,928		13,742

Commitments and contingencies
Minority interest of consolidated subsidiary		1		2
Member’s equity
Membership interest		3,220		3,220
Undistributed earnings		1,448		1,002
Accumulated other comprehensive income (loss)		5		(242	)

Total member’s equity		4,673		3,980

Total liabilities and member’s equity	$	17,602	$	17,724

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN MEMBER’S EQUITY

(Unaudited)


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

Balance, December 31, 2005	$	3,220	$	1,002		$	(242	)	$	3,980
Net income		—		768			—			768
Distribution to member		—		(322	)		—			(322	)
Other comprehensive income, net of income taxes of $(106)		—		—			247			247

Balance, June 30, 2006	$	3,220	$	1,448		$	5		$	4,673

See the Combined Notes to Consolidated Financial Statements

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


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

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

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

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

The accompanying consolidated financial statements as of June 30, 2006 and 2005 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 (collectively, the Registrants), include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2005 Consolidated Balance Sheets were taken from audited financial statements. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports onForm 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or shareholders’ or Member’s equity. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation included in ITEM 8 of their 2005 Annual Report onForm 10-K.


2.	Discontinued Operations (Exelon and Generation)

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

(for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Income and Comprehensive Income. Results for the three and six months ended June 30, 2005 related to these entities were as follows:


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

Total operating revenues	$	—		$	4		$	4
Operating loss		—			(2	)		(2	)
Loss before income taxes		(2	)(c)		(1	)		(3	)


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

(b)		Excludes certain investments.

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


Six Months Ended June 30, 2005	Sithe(a)			Enterprises(b)			Total

Total operating revenues	$	30		$	8		$	38
Operating income (loss)		5			(4	)		1
Income (loss) before income taxes		18	(c)		(5	)		13


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

(b)		Excludes certain investments.

(c)		Sithe includes a pre-tax gain on sale of $19 million.

For the three and six months ended June 30, 2006, Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income included $3 million of income (after tax) from discontinued operations related to Sithe, which represented an adjustment to the gain on sale as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

Exelon has sold various investments and long-lived assets which do not qualify to be presented as discontinued operations.


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

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

SFAS No. 123-R

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

prospective awards using the modified prospective transition method without restatement of prior periods. At June 30, 2006, there were approximately 28.2 million shares remaining for issuance under the LTIPs.

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


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Components of Stock-Based Compensation Expense	2006		2005		2006		2005

Stock options	$	8	$	—	$	25	$	—
Performance shares		20		11		41		22
Other stock-based awards		2		3		3		5

Total stock-based compensation included in operating and maintenance expense		30		14		69		27

Income tax benefit		11		5		26		10

Total after-tax stock-based compensation expense	$	19	$	9	$	43	$	17

The following table presents ComEd’s, PECO’s and Generation’s stock-based compensation expense (pre tax) during the three and six months ended June 30, 2006 and 2005:


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Registrant	2006		2005		2006		2005

ComEd	$	9	$	3	$	19	$	5
PECO		4		2		10		3
Generation		17		9		39		17

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock are granted under the LTIPs. As a result of adoptingSFAS No. 123-R, Exelon expensed $8 million and $25 million of stock options during the three and six months ended June 30, 2006, respectively.

The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options granted under the LTIPs generally become exercisable upon a specified vesting date. Shares subject to stock options are typically issued from authorized but unissued common stock shares. All stock options expire 10 years from the date of grant. The vesting period of stock options outstanding as of June 30, 2006 generally ranged from 3 years to 4 years. The value of stock options at the date of grant is either amortized through expense over the requisite service period using the straight-line method or capitalized. For stock options granted to retirement eligible employees, the value of the stock option is recognized immediately on the date of grant. There were no significant stock-based compensation costs capitalized during the three and six months ended June 30, 2006 and 2005.

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

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


	Six Months
	Ended
	June 30,
	2006			2005

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

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

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

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


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

Balance at December 31, 2005		21,674,270		$	31.23
Options granted/assumed		4,075,145			58.55
Options exercised		(3,433,230	)		29.17
Options forfeited/cancelled		(214,391	)		40.82

Balance at June 30, 2006		22,101,794			36.48		7.05	$	449,801,532

Exercisable at June 30, 2006(a)		11,087,045			30.30		5.74		294,184,725


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

Intrinsic value for stock-based instruments is defined as the difference between the current market value and the exercise price. The total intrinsic value of stock options exercised during the three and six months ended June 30, 2006 was $23 million and $93 million, respectively, and $46 million and $124 million for the three and six months ended June 30, 2005.

During the three and six months ended June 30, 2006, cash received from stock options exercised was $23 million and $100 million, respectively, and the actual tax benefit realized for tax deductions from stock options exercised was $9 million and $37 million, respectively. During the three and six months ended June 30, 2005, cash

received from stock options exercised was $49 million and $150 million, respectively, and the actual tax benefit realized for tax deductions from stock options exercised was $18 million and $50 million, respectively.SFAS No. 123-R requires the benefits of tax deductions in excess of the compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. There was $29 million of excess tax benefits included as a cash inflow in other financing activities in Exelon’s Consolidated Statement of Cash Flow for the six months ended June 30, 2006. Prior to the adoption ofSFAS No. 123-R, Exelon presented these benefits as operating cash flows in the Consolidated Statement of Cash Flows.

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


				Weighted
				Average
				Exercise
				Price
	Shares			(per share)

Nonvested at December 31, 2005		12,000,284		$	35.42
Granted		4,075,145			58.55
Vested		(4,839,877	)		37.91
Forfeited		(220,803	)		41.92

Nonvested at June 30, 2006		11,014,749			42.70

As of June 30, 2006, $61 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the weighted-average period of 3 years. The total grant date fair value of stock options vested, including the capitalized amount, during the three and six months ended June 30, 2006 was $8 million and $26 million, respectively. The total grant date fair value of stock options vested during the three and six months ended June 30, 2005 was $6 million and $12 million, respectively.

Performance Share Awards

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

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

Performance share awards to be settled in stock are fair valued at the date of grant. Performance share awards to be settled in cash are remeasured each reporting period throughout the vesting period. As a result, the compensation costs for cash settled awards is subject to variability. The fair value of each performance share award granted during the six months ended June 30, 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year. This model requires assumptions regarding Exelon’s total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. Expected volatility is based on historical information. Additionally, Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted if necessary.

For non retirement-eligible employees, compensation costs are accrued and expensed over the vesting period of three years using the graded vesting method. As a result of adoptingSFAS No. 123-R, Exelon recognizes ratably throughout the year of grant the entire compensation cost of new common stock awards in which retirement-eligible

employees are fully vested in the year of grant (non-substantive vesting approach). Prior to the adoption ofSFAS No. 123-R on January 1, 2006, such compensation cost was recognized over the nominal vesting period of performance with any remaining compensation cost recognized at the date of retirement. The impact of using this approach related to performance share awards was $3 million and $5 million during the three and six months ended June 30, 2006, respectively. Exelon recognized compensation expense related to performance share awards (before income taxes) of $20 million and $41 million during the three and six months ended June 30, 2006, respectively, and $11 million and $22 million during the three and six months ended June 30, 2005, respectively. This compensation expense includes awards granted prior to 2006.

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

At June 30, 2006, Exelon had an obligation related to outstanding awards not yet settled of $52 million, of which $23 million and $29 million is included in common stock and deferred credits and other liabilities, respectively, in Exelon’s Consolidated Balance Sheet. At December 31, 2005, Exelon had an obligation related to outstanding awards not yet settled of $51 million, of which $27 million and $24 million is included in common stock and deferred credits and other liabilities, respectively, in Exelon’s Consolidated Balance Sheet.

Other Stock-Based Awards

Exelon also issues common stock through an employee stock purchase plan and through restricted stock units and accounts for these awards in accordance withSFAS No. 123-R. The compensation cost of these types of issuances was immaterial during the three and six months ended June 30, 2006 and 2005. However, at June 30, 2006 and December 31, 2005, Exelon had an obligation related to outstanding restricted stock not yet settled of $10 million and $19 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

Directors and executives are able to defer stock awards granted to them through Exelon’s stock-based compensation programs into the Exelon Corporation Stock Deferral Plan. At June 30, 2006 and December 31, 2005, Exelon had an obligation related to this plan of $36 million and $30 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

2005 Pro Forma Information

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


	Three Months			Six Months
	Ended			Ended
	June 30, 2005			June 30, 2005

Net income — as reported	$	514		$	1,035
Add: Stock-based compensation expense included in reported net income, net of income taxes		9			17
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes(a)		(12	)		(24	)

Pro forma net income	$	511		$	1,028

Earnings per share:
Basic — as reported	$	0.77		$	1.55
Basic — pro forma		0.76			1.54
Diluted — as reported		0.76			1.53
Diluted — pro forma		0.75			1.52


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

Had Exelon recognized the entire compensation cost of its stock-based awards in which retirement-eligible employees were fully vested upon issuance for stock options, and in the first year for performance share awards (non-substantive vesting approach), as now required underSFAS No. 123-R, stock-based compensation expense would have been $1 million lower and $3 million higher after taxes than reflected in the table above for the three and six months ended June 30, 2005, respectively. These pro forma amounts of $1 million and $3 million were calculated as ifSFAS No. 123-R had always been implemented. However, at the time of adoption on January 1, 2006, the compensation cost of stock-based awards issued to retirement eligible employees was recognized using the non-substantive vesting approach prospectively.

EITF 04-13

In September 2005, the FASB ratified Emerging Issues Task Force (EITF) IssueNo. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”(EITF 04-13).EITF 04-13 provides guidance on whether two or more inventory purchase and sales transactions with the same counterparty should be viewed as a single exchange transaction within the scope of APB No. 29, “Accounting for Nonmonetary Transactions.” In addition,EITF 04-13 indicates whether nonmonetary exchanges of inventory within the same line of business should be recognized at cost or fair value.EITF 04-13 was effective as of April 1, 2006 and the adoption of this standard did not have a material impact on the Registrants for the three months ended June 30, 2006.

FSP No. FIN 46(R)-6

In April 2006, the FASB issued FASB Staff Position No. FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP No. 46(R)-6). This pronouncement provides guidance on how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” which could impact the assessment of whether certain variable interest entities are consolidated. FSP No. 46(R)-6 was effective for the Registrants on July 1, 2006. The provisions of FSP No. 46(R)-6 are applied prospectively. The

impact on the Registrants in periods subsequent to the effective date is dependent on transactions that could occur in future periods and, therefore, cannot be determined until the transactions occur.

SFAS No. 155

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

SFAS No. 156

In March 2006, the FASB issued FASB Statement No. 156, “Accounting for Servicing of Financial Assets, amendment of FASB Statement No. 140” (SFAS No. 156). SFAS No. 156 amends SFAS No. 140 with respect to the accounting for separately recognized servicing assets and liabilities. SFAS No. 156 primarily requires companies to initially record separately recognized servicing rights at fair value, allows companies to choose between two measurement methods and provides additional disclosure requirements. SFAS No. 156 will be effective for the Registrants as of January 1, 2007 and the Registrants are currently assessing the impact that SFAS No. 156 may have on their financial statements.

FIN 48

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return. The change in net assets as a result of applying this pronouncement will be considered a change in accounting principle with the cumulative effect of the change treated as an offsetting adjustment to the opening balance of retained earnings or goodwill, if allowed under existing accounting standards, in the period of transition. FIN 48 is effective for the Registrants as of January 1, 2007 and the Registrants are currently assessing the impact that FIN 48 will have on their financial statements, which may be significant. Two of Exelon’s and ComEd’s most significant uncertain tax positions related to the 1999 sale of ComEd’s fossil generating assets are further described in Note 10 — Income Taxes.

EITF 06-3

In June 2006, the FASB ratified EITF IssueNo. 06-3, “How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)”(EITF 06-3).EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition,EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented.EITF 06-3 will be effective for the Registrants as of January 1, 2007. The

Registrants disclose taxes that are imposed on and concurrent with a specific revenue-producing transaction in accordance with EITF IssueNo. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” ComEd’s and PECO’s utility taxes are presented on a gross basis (see Note 15 — Segment Information). AsEITF 06-3 provides only disclosure requirements, the adoption of this standard is not expected to have a material impact on the Registrants.


4.	Acquisitions and Dispositions (Exelon and Generation)

Proposed Merger with PSEG (Exelon)

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). PSEG shareholders approved the Merger on July 19, 2005. Exelon shareholders approved the issuance of Exelon shares pursuant to the Merger on July 22, 2005. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock.

On May 30, 2006, the Nuclear Regulatory Commission (NRC) approved the transfer of the operating licenses for the Salem and Hope Creek nuclear power plants, and the non-operating ownership interest in Peach Bottom units 2 and 3, from PSEG to Exelon. On June 22, 2006, Exelon and PSEG reached a comprehensive agreement with the Antitrust Division of the United States Department of Justice (DOJ), which resolves all competition issues reviewed by the DOJ in connection with the Merger. Under the terms of the DOJ agreement, Exelon and PSEG will divest six fossil-fuel fired electric generating plants, two in Pennsylvania and four in New Jersey, with a total capacity of approximately 5,600 megawatts. The owners of the six plants are required to enter into contracts for sale of the plants within 150 days after the Merger closes and will give DOJ approval rights over the buyers to assure a competitive market after the divestiture. The two plants Exelon is required to sell are the Eddystone Generating Station and Cromby Generating Station in Pennsylvania. No divestitures will be required unless the Merger is completed.

As of July 30, 2006, all regulatory approvals or reviews necessary to consummate the Merger have been completed with the exception of the approval from the New Jersey Board of Public Utilities (NJBPU). Hearings before the administrative law judge in the NJBPU proceedings were completed on March 31, 2006, and settlement discussions with the NJBPU staff and other parties resumed in May 2006 and are continuing. Exelon and PSEG recently made an enhanced settlement proposal in New Jersey that includes concessions that are significantly greater than the concessions originally offered. Exelon and PSEG have also indicated that it is essential to reach settlement promptly. If Exelon and PSEG are able to reach a settlement in New Jersey, the settlement would need to be reviewed by the administrative law judge presiding over the case and would need to be approved by the NJBPU after public comment. Although it is possible that this process could be completed in time to allow the Merger to close in the third quarter of 2006, there is currently no established timetable for NJBPU action on the Merger. The final decision on whether to proceed with the Merger will rest with the boards of both Exelon and PSEG after terms and conditions of regulatory requirements are known.

Immediately after consummation of the Merger, the generation business of PSEG known as PSEG Power will be merged with and into Generation, which will succeed to all the assets and liabilities of PSEG Power, and PSEG Power will cease to exist.

Exelon has capitalized certain external costs associated with the Merger since the execution of the Merger Agreement on December 20, 2004. Total capitalized costs of $52 million and $46 million are included in deferred debits and other assets on Exelon’s Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005, respectively.

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

Sithe (Exelon and Generation)

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s (Reservoir) 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy).

In connection with the sale, Exelon recorded $55 million of liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. Generation issued certain guarantees associated with income tax indemnifications to Dynegy in connection with the sale that were valued at approximately $8 million (included in the $55 million accrual discussed above), of which $7 million has expired as of June 30, 2006. These guarantees are being accounted for under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45). The exposures covered by these indemnities are anticipated to expire in 2006 and beyond. These liabilities were taken into account in the determination of the net gain on the sale of $21 million (before income taxes), which was adjusted to $24 million (before income taxes) in the third quarter of 2005. As of June 30, 2006, Exelon’s accrued liabilities related to these indemnifications and guarantees were $40 million, including $1 million related to income tax indemnifications. The net decrease for the accrual initially established was due to the expiration of certain guarantees, tax indemnifications and collections on certain assets that were associated with the sales transaction. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $175 million at June 30, 2006.

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


	Three Months			Six Months
	Ended			Ended
	June 30, 2005(a)			June 30, 2005(b)

Operating revenues	$	—		$	30
Operating income		—			5
Net income (loss)		(1	)		15(c	)


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

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

(c)		Includes a pre-tax gain on sale of Sithe of $19 million.

Exelon’s and Generation’s Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2006 included a $3 million (after-tax) gain as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

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


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

ComEd

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

Illinois Procurement Filing. On February 25, 2005, ComEd made a filing with the Illinois Commerce Commission (ICC) to seek regulatory approval of tariffs that would authorize ComEd to bill its customers for power costs incurred under a reverse-auction competitive bidding process (the Procurement Case). On January 24, 2006,

the ICC, by a unanimous vote, approved the tariffs for the period commencing January 2, 2007. The reverse-auction competitive bidding process will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during September 2006, at which time ComEd’s entire retail load will be up for bid. In order to mitigate the effects of the changes in future prices, the load for residential and commercial customers less than 400 kW will be served utilizing staggered three-year contracts. The ICC determined that it will review the prudence of ComEd’s purchase of power but that compliance with the ICC-approved process will establish a presumption of prudence. Various parties, including governmental and consumer representatives and ComEd, have filed petitions for review of portions of the order with the Illinois Appellate Court. While ComEd is generally supportive of the order in the Procurement Case, ComEd has objected to the requirement for a prudence review. On June 2, 2006, the Illinois Attorney General filed a petition with the Illinois Supreme Court asking the Supreme Court to hear the matter on direct appeal and to grant expedited review of the pending appeals and stay implementation of the auction pending appeal. The petition is fully briefed and awaiting action by the Supreme Court. In the meantime, the Illinois Appellate Court has stayed all proceedings before it pending action by the Illinois Supreme Court.

The ICC, in its January 24, 2006 order, also ordered its staff to initiate three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources. These rulemakings are now proceeding with ComEd’s active participation.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC to comprehensively review its tariff and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). ComEd proposed a revenue increase of $317 million. The ICC staff and several intervenors in the Rate Case, including the Illinois Attorney General, suggested and provided testimony that ComEd’s rates for delivery services should be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case. On June 8, 2006, the administrative law judges issued a proposed order, which included a revenue increase of $164 million plus ComEd’s request for recovery of several items which previously were recorded as expense. On July 26, 2006, the ICC issued its order in the Rate Case which approved a delivery services revenue increase of $8 million. The ICC order did approve ComEd’s requested recovery of several items which previously were recorded as expense. However, the ICC disallowed rate base treatment (return) for ComEd’s prepaid pension asset, net of deferred taxes, of $639 million. This disallowance will not result in an immediate write-off since the pension asset will be recovered as pension cost is recognized and recovered from customers in the future but will reduce ComEd’s future return on equity until the asset is recovered. See Note 13 — Commitments and Contingencies for further information. The final order in the Rate Case is subject to rehearing and appeal. ComEd believes that the disallowances contained in the order are inappropriate and intends to vigorously pursue these issues on rehearing and appeal.

Original Cost Audit. In the Rate Case, the ICC, with ComEd’s concurrence, ordered an “original cost” audit of ComEd’s distribution assets. There was no suggestion in the case that any specific asset should be disallowed because it was unreasonable in amount, imprudently incurred or not used and useful. The ICC’s order does not provide for a new review of these issues but instead provides that the auditors will determine whether the costs were properly recorded on ComEd’s financial statements as distribution assets. This will be completed through a separately docketed proceeding. The original cost audit is not expected to be finalized in 2006. ComEd is unable to predict the results of this audit.

Residential Rate Stabilization Program. On May 23, 2006, ComEd filed a proposal with the ICC to mitigate the impact of the transition to the post rate-freeze period on its residential customers. Under ComEd’s proposal, residential rate increases would be capped at 8% in 2007, an additional 7% in 2008, and an additional 6% in 2009. Costs that exceed the caps would be deferred and recovered with ComEd’s carrying charges over three years from 2010 to 2012. If ComEd’s rate increases are less than the caps in 2008 and 2009, ComEd would begin to recover deferred amounts up to the caps. The plan would terminate under a force majeure event or if ComEd’s senior unsecured credit rating from at least one of the three major credit rating agencies falls below investment grade. The

ICC staff, the Illinois Attorney General and collectively the City of Chicago, Citizens Utility Board and Cook County States Attorney’s Office filed testimony objecting to all or parts off the proposal. ComEd is reviewing this initiative in light of the ICC order in the Rate Case.

Renewable Energy Filing. On April 4, 2006, ComEd filed with the ICC a proposal to purchase and receive recovery of costs associated with purchasing the output of a portfolio of wind resources of approximately 300 MW. The filing supports the ICC’s resolution of July 19, 2005 which endorsed the Illinois Governor’s proposal for a voluntary initiative in which electric suppliers would obtain resources equal to 2% of electricity sold to Illinois retail customers from renewable energy resources by the end of 2007 and gradually increasing to a target of 8% by 2013 (the Plan). This filing covers the first year’s wind-only procurement associated with the Plan. Additionally, the filing expresses ComEd’s support of the renewable, efficiency and demand response rulemaking proceedings ordered by the ICC in the Procurement Case. Actual purchase of wind resources is contingent upon an ICC order approving the prudence of this activity and authorizing cost recovery. ComEd will file additional renewable energy, demand response and energy efficiency components sometime in the future, pending outcomes in those rulemakings. ComEd is reviewing this initiative in light of the ICC order in the Rate Case.

Rate Freeze Extension Proposal. On February 24, 2006, House Bill 5766 was introduced in the Illinois General Assembly and was referred to the Rules Committee. House Bill 5766, if enacted, would extend the current rate freeze in Illinois until at least 2010. The Illinois General Assembly took no action on the bill and is now adjourned. It is scheduled to resume session in November 2006. ComEd believes the proposed legislation, if enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. ComEd believes the proposed rate freeze extension, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to challenge the rate freeze legislation in court. If enacted, this legislation would have adverse liquidity consequences for ComEd.

Customers’ Affordable Reliable Energy. In July 2006, ComEd implemented Customers’ Affordable Reliable Energy (CARE), an initiative to help residential customers prepare for electricity rate increases coming in 2007 after the expiration of the rate freeze in Illinois. In addition to the residential rate stabilization proposal, CARE includes a variety of energy efficiency and low-income and senior citizen programs to help keep residential customers’ bills affordable. ComEd has earmarked approximately $10 million for CARE in 2006.

Post 2006 Summary. ComEd cannot predict the results of any rehearings or appeals in the Rate Case or the Procurement Case or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the regulatory process. However, if the price which ComEd is ultimately allowed to bill to customers for energy beginning in 2007 is below ComEd’s cost to procure and deliver electricity, ComEd expects that it will suffer adverse consequences, which could be material. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, reduced earnings for Exelon and ComEd, loss of ComEd’s investment grade credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term energy procurement contracts, which may force ComEd to procure electricity at more volatile spot market prices. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. Finally, if ComEd’s ability to recover its costs from customers through rates is significantly impacted, all or a portion of ComEd’s business could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71) which covers the accounting for the effects of rate regulation and which would require Exelon and ComEd to eliminate the financial statement effects of regulation for the portion of ComEd’s business that ceases to meet the criteria. This would result in the elimination of all associated regulatory assets and liabilities that Exelon and ComEd had recorded on their Consolidated Balance Sheets through the recording of a one-time extraordinary item on their Consolidated Statements of Income and Comprehensive Income, which could be material.

PECO

Partial Settlement before the Pennsylvania Public Utility Commission (PAPUC). On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s electric distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement electric rate reductions aggregating $120 million during a four-year period and to cap its electric rates through the end of 2010. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. See Note 4 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for further discussion.

ComEd and PECO

Through and Out Rates/SECA. In November 2004, the Federal Energy Regulatory Commission (FERC) issued two orders authorizing ComEd and PECO to recover amounts for a limited time during a specified transitional period as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of, or across, their respective transmission systems and ending within pre-expansion territories of PJM Interconnection, LLC (PJM) or Midwest Independent System Operators (MISO). T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), were collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As load-serving entities, ComEd and PECO were also required to pay SECA rates during the transitional period based on the benefits they receive from the elimination of T&O rates of other transmission owners within PJM and MISO. Since the inception of the SECA rates in December 2004, ComEd has recorded approximately $49 million of SECA collections net of SECA charges, including $5 million during the six months ended June 30, 2006, while PECO has recorded $10 million of SECA charges net of SECA collections, including $3 million during the six months ended June 30, 2006. As a result of recent events related to disputes over the methodology of computing SECA amounts, during the first quarter of 2006, ComEd and PECO increased their previously-recorded reserves for amounts to be refunded. Management of each of ComEd and PECO believes that appropriate reserves have been established in the event that SECA collections are required to be refunded. Hearings and briefing of the matter have been concluded and an initial decision of the presiding administrative law judge is expected on or before August 11, 2006. Meanwhile, partial settlements have been reached with various parties. FERC has approved several of the partial settlements while others are still awaiting final executionand/or FERC approval. The ultimate outcome of the proceeding establishing SECA rates is uncertain.

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

On July 13, 2006, the administrative law judge in the case issued an initial decision that recommends that the FERC implement the postage stamp rate suggested by FERC staff, effective as of April 1, 2006, but also allows for the potential to phase in rate changes. On review of the matter, the FERC will determine whether changes in rate design should be made, what those changes should be and their effective date. There is no set timeline for the FERC to act on this matter. ComEd and PECO will continue to contest this issue and currently cannot predict how the FERC will ultimately rule on this matter or estimate the final impact on either company’s results of operations and cash flows. However, ComEd anticipates that, with the completion of the rate freeze at the end of this year, beginning in 2007, all impacts of any rate design changes should be recoverable through retail rates.

Generation

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


6.	Intangible Assets (Exelon and ComEd)

Goodwill (Exelon and ComEd). As of June 30, 2006 and December 31, 2005, Exelon and ComEd had goodwill of approximately $3.5 billion. Under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), goodwill is tested for impairment at least annually or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired, such as a significant negative regulatory outcome. Exelon and ComEd perform their annual goodwill impairment assessment in the fourth quarter of each year. However, due to the significant negative impact of the ICC’s order in ComEd’s Rate Case to the cash flows and value of ComEd, it will complete an interim impairment assessment during the third quarter of 2006. This interim impairment test may lead to an impairment of goodwill at both Exelon and ComEd. The size of any potential impairment will not be known until ComEd completes its test in the third quarter but any impairment could be material. See Note 5 — Regulatory Issues for further information regarding the Rate Case.

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


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

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

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


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

For the three and six months ended June 30, 2006, Exelon’s amortization expense related to intangible assets was $12 million and $28 million, respectively. For the three and six months ended June 30, 2005, Exelon’s amortization expense related to intangible assets was $15 million and $35 million, respectively.


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

Commercial Paper

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


	June 30,		December 31,
Borrower	2006		2005

Exelon	$	10	$	—
ComEd		339		459
PECO		227		220
Generation		309		311

Credit Facilities

As of June 30, 2006, Exelon, PECO and Generation participated with a group of banks in a $1 billion unsecured revolving credit facility maturing on July 16, 2009 and a $500 million unsecured revolving credit facility maturing on October 31, 2006. These agreements were amended on February 22, 2006 to remove ComEd as a borrower and to remove provisions that would treat ComEd as a significant subsidiary of Exelon for purposes of its covenants and defaults under the credit agreements. See Note 10 of Exelon’s 2005 Annual Report onForm 10-K for further information regarding these credit facilities. In addition to these credit facilities, during the first quarter of 2006, Generation and ComEd each executed new credit facility agreements which are described below. The Registrants may use the credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Generation

On February 10 through 16, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $950 million. The additional credit facilities are each for a term of 364 days and contain the same terms as the revolving credit facilities described in Note 10 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K.

ComEd

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

Issuance of Long-Term Debt

During the six months ended June 30, 2006, the following long-term debt was issued:

Interest

Company

Type

Rate

Maturity

Amount

ComEd

First Mortgage Bonds

5.90

March 15, 2036

325

(a)

PECO

Notes payable, accounts receivable agreement

5.22

November 12, 2010


(a)		Excludes unamortized bond discounts.

Retirement of Long-Term Debt

During the six months ended June 30, 2006, the following long-term debt was retired:


		Interest
Company	Type	Rate			Maturity	Amount

Exelon	Notes payable for investments in synthetic fuel-producing facilities		6.00-8.00	%	Various	$	33
ComEd	Sinking Fund Debentures		4.75	%	December 1, 2011		1
ComEd	ComEd Transitional Funding Trust		5.63	%	June 25, 2007		174
PECO	PECO Energy Transition Trust (PETT)		6.05	%	March 1, 2007		248

SCEP

Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of Southeast Chicago Energy Project, LLC (SCEP), a 350-megawatt natural gas-fired, peaking electric power plant located in Chicago, Illinois, which began operation in 2002. In 2002, Generation and Peoples Calumet owned 70% and 30%, respectively, of SCEP. Generation had reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a20-year period.

On March 31, 2006, Generation entered into an agreement to accelerate the acquisition of Peoples Calumet’s interest in SCEP. This transaction closed on May 31, 2006. Under the agreement, Generation paid Peoples Calumet approximately $47 million for its remaining interest in SCEP. Generation financed this transaction using short-term debt and available cash.


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

The following tables present total salary continuance severance costs (benefits), recorded as operating and maintenance expense, for the three and six months ended June 30, 2006 and 2005:


Salary Continuance Severance	ComEd			PECO		Generation			Other(a)			Exelon

Expense recorded for the three months ended June 30, 2006	$	—		$	—	$	—		$	—		$	—
Expense (income) recorded for the six months ended June 30, 2006		(2	)		—		1	(c)		2	(b)		1	(b),(c)


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

(b)		Includes $1 million of severance related to stock-based compensation, which is not included in the salary continuance severance obligations table below.

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


Salary Continuance Severance	ComEd			PECO		Generation			Other(a)		Exelon

Expense (income) recorded for the three months ended June 30, 2005	$	(3	)	$	—	$	(1	)	$	2	$	(2	)
Expense (income) recorded for the six months ended June 30, 2005		(4	)		1		(2	)		1		(4	)


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

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


Salary Continuance Obligations	ComEd			PECO		Generation			Other(a)			Exelon

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

Balance at June 30, 2006	$	5		$	1	$	6		$	4		$	16


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


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

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


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

Service cost	$	38		$	38		$	25		$	23
Interest cost		139			139			44			43
Expected return on assets		(204	)		(192	)		(27	)		(24	)
Amortization of:
Transition obligation (asset)		—			(1	)		3			2
Prior service cost (benefit)		4			4			(23	)		(22	)
Actuarial loss		34			30			21			17

Net periodic benefit cost	$	11		$	18		$	43		$	39


	Pension						Other
	Benefits						Postretirement
	Six Months						Benefits
	Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005

Service cost	$	79		$	76		$	50		$	47
Interest cost		281			278			91			86
Expected return on assets		(408	)		(385	)		(53	)		(49	)
Amortization of:
Transition obligation (asset)		—			(2	)		5			5
Prior service cost (benefit)		8			8			(46	)		(45	)
Actuarial loss		74			60			44			33

Net periodic benefit cost	$	34		$	35		$	91		$	77

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


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Pension and Postretirement Benefit Costs(a),(b)	2006		2005		2006		2005

ComEd	$	20	$	22	$	43	$	43
PECO		6		7		18		14
Generation		28		27		63		54


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

(b)		Includes allocated amounts from BSC.

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, 2006 and 2005:


	Three Months				Six Months
	Ended				Ended
	June 30,				June 30,
Savings Plan Matching Contributions	2006		2005		2006		2005

Exelon	$	15	$	15	$	30	$	29
ComEd		4		4		8		8
PECO		1		1		3		3
Generation		8		7		16		14

The U.S. Congress is currently considering legislation that, if adopted, would affect the manner in which Exelon administers its pensions. This proposed legislation is designed, among other things, to increase the amount by which companies fund their pension plans and to require companies that sponsor defined benefit plans to pay higher premiums to the Pension Benefit Guaranty Corporation. If this proposed legislation becomes law, Exelon, under certain future circumstances, could become subject to additional material funding requirements.

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

Exelon

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


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2006			2005			2006			2005

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.7			3.4			3.6			3.7
Synthetic fuel-producing facilities credit(a)		—			(8.8	)		(1.6	)		(8.1	)
Qualified nuclear decommissioning trust fund income		0.3			1.0			0.4			0.7
Domestic production activities deduction		(0.5	)		(0.2	)		(0.6	)		(0.2	)
Tax exempt income		(0.3	)		(0.4	)		(0.4	)		(0.4	)
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(0.3	)		(0.3	)
Amortization of investment tax credit		(0.3	)		(0.3	)		(0.4	)		(0.3	)
Other		(1.4	)		(0.9	)		(0.6	)		(0.3	)

Effective income tax rate		36.2	%		28.6	%		35.1	%		29.8	%


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

ComEd

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


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2006			2005			2006			2005

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		4.9			4.8			4.8			4.8
Amortization of regulatory asset		0.7			0.8			0.7			0.8
Nontaxable postretirement benefits		(0.3	)		(0.4	)		(0.4	)		(0.5	)
Amortization of investment tax credit		(0.3	)		(0.4	)		(0.5	)		(0.5	)
Other		0.4			(0.4	)		0.9			0.1

Effective income tax rate		40.4	%		39.4	%		40.5	%		39.7	%

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						Ended
	June 30,						June 30,
	2006			2005			2006			2005

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		(2.1	)		(3.5	)		(1.3	)		(1.7	)
Plant basis differences		0.8			(0.7	)		0.4			(0.2	)
Nontaxable postretirement benefits		(0.3	)		(0.3	)		(0.3	)		(0.2	)
Amortization of investment tax credit		(0.4	)		(0.4	)		(0.4	)		(0.3	)
Other		(0.4	)		(0.2	)		(0.1	)		0.5

Effective income tax rate		32.6	%		29.9	%		33.3	%		33.1	%

Generation

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


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2006			2005			2006			2005

U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		4.4			4.3			4.4			4.6
Qualified nuclear decommissioning trust fund income		0.4			1.5			0.5			1.0
Domestic production activities deduction		(0.6	)		(0.3	)		(0.8	)		(0.3	)
Tax exempt income		(0.4	)		(0.6	)		(0.5	)		(0.5	)
Nontaxable postretirement benefits		(0.2	)		(0.2	)		(0.2	)		(0.2	)
Amortization of investment tax credit		(0.1	)		(0.2	)		(0.2	)		(0.2	)
Other		(1.3	)		(1.1	)		(1.0	)		(0.9	)

Effective income tax rate		37.2	%		38.4	%		37.2	%		38.5	%

Investments in Synthetic Fuel-Producing Facilities (Exelon)

Exelon, through three separate wholly owned subsidiaries, owns interests in two limited liability companies and one limited partnership that own synthetic fuel-producing facilities. Section 45K (formerly Section 29) of the Internal Revenue Code (IRC) provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45K contains a provision under which the tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. On April 11, 2006, the Internal Revenue Service (IRS) published the 2005 oil Reference Price and it did not exceed the beginning of the phase-out range. As such, there was not a phase-out of tax credits for calendar year 2005.

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


	Estimated
	2006

Beginning of Phase-Out Range(a)	$	60
End of Phase-Out Range(a)		76
2006 Annual Average NYMEX		71


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

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to idle synthetic fuel production was primarily driven by the level and volatility of oil prices in the second quarter of 2006. In addition, the proposed Federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. Synthetic fuel production may resume in the future, but is dependent upon various factors, including a reduction in oil prices or the enactment of future federal tax legislation.

The net carrying value of the intangible assets associated with the synthetic fuel-producing facilities was $143 million at December 31, 2005. See Note 6 — Intangible Assets for additional information. As a result of the suspension of production at the synthetic fuel-producing facilities and the level of oil prices, Exelon does not anticipate earning sufficient future tax credits to support the value of the intangible asset associated with its investment in synthetic fuel-producing facilities. In the second quarter of 2006, Exelon recorded an impairment charge of $115 million ($69 million after tax) to impair the aforementioned intangible asset.

Prior to the idling of the synthetic fuel-producing facilities, Exelon was required to pay for tax credits based on the production of the facilities regardless of whether or not a phase-out of the tax credits was anticipated. However, Exelon has the legal right to recover a portion of the payments made to its counterparties related to phased-out tax credits. At June 30, 2006, Exelon had receivables on its Consolidated Balance Sheet from the counterparties totaling $53 million associated with the portion of the payments previously made to the counterparties related to tax credits that are anticipated to be phased out in 2006. This receivable is net of adjustments made for the credit risk associated with the counterparties. As of June 30, 2006, Exelon has estimated the 2006 phase-out to be 70%, which has reduced Exelon’s after-tax credits of $86 million to $26 million for the six months ended June 30, 2006. These credits may be further phased out during the remainder of 2006 depending on the price of oil; however, as these tax credits are phased out, Exelon anticipates recording income from derivatives entered into in 2005 (as more fully described below).

In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of the exposure to a phase-out of the tax credits. One of the counterparties has security interests in these derivatives. Including the relatedmark-to-market gains on these derivatives, interests in synthetic fuel-producing facilities reduced Exelon’s net income by $55 million and increased Exelon’s net income by $29 million during the three months ended June 30, 2006 and 2005, respectively. Additionally, interests in synthetic fuel-producing facilities reduced net income by $43 million and increased net income by $45 million during the six months ended June 30, 2006 and 2005, respectively. Exelon anticipates that it will continue to record income or losses related to themark-to-market gains/losses, changes to the tax credits earned by Exelon during the period of production as a result of volatility in oil prices and a gain on the eventual settlement of the derivatives.

Net income from interests in synthetic fuel-producing facilities is reflected in the Consolidated Statements of Income and Comprehensive Income as a benefit within income taxes and amark-to-market gain in operating and maintenance expense, offset by charges to operating and maintenance expense, depreciation and amortization expense, interest expense and equity in losses of unconsolidated affiliates.

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

The non-recourse notes payable principal balance was $125 million and $158 million at June 30, 2006 and December 31, 2005, respectively. The non-recourse notes payable can be relieved either through eventual payments or possibly through extinguishment which may occur subsequent to termination of the partnership pursuant to the agreements between the parties.

1999 Sale of Fossil Generating Assets (Exelon and ComEd)

Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of June 30, 2006 and December 31, 2005, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to ComEd and the remainder to Generation. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to applicable law. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction ComEd entered into in connection with the sale is proper pursuant to applicable law. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. The IRS has recently indicated its position that the ComEd lease transaction is substantially similar to a leasing transaction the IRS is treating as a “listed transaction” pursuant to guidance it issued in 2005. A listed transaction is one which the IRS considers to be a potentially abusive tax shelter. As a result of the IRS characterization of the lease transaction as a listed transaction, it is likely to vigorously challenge the transaction and will seek to obtain information not normally requested in audits. Exelon believes its position is correct and will aggressively defend that position upon audit and any subsequent appeals or litigation. However, a successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes currently payable. As of June 30, 2006, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $954 million. If the deferral were successfully challenged by the IRS, it could negatively affect Exelon’s results of operations by as much as $149 million (after tax). Exelon’s management believes a reserve for interest has been appropriately recorded in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5); however, the ultimate outcome of this matter could result in unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Final resolution of this matter is not anticipated for several years.

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

Generation has supplied nearly 100% of ComEd’s requirements since its formation in 2001, representing between 40% and 50% of Generation’s supply resources. Commencing January 2, 2007, ComEd will no longer have a purchase power agreement (PPA) with Generation and instead ComEd will procure power through a reverse-auction competitive bidding process. In addition to the power Generation may sell directly to ComEd (restricted to 35% of power purchased by ComEd in the reverse-auction competitive bidding process for each auction section),

Generation will enter into contractual arrangements with third parties that may provide power to ComEd under contracts entered into pursuant to the reverse-auction competitive bidding process.

Also as a result of the termination of the PPA and the transition to market based rates, Exelon’s revenues are anticipated to increase due to the increase in the amount of power Generation will sell to third parties in the wholesale energy market instead of through its previous intercompany transactions with ComEd through the PPA, and, based on recent increases in market prices, ComEd’s revenues will increase as the price of power will be passed onto customers. For Illinois income tax purposes, income is apportioned to Illinois based on the relationship of Illinois-sourced gross receipts to total gross receipts, determined on a consolidated basis. As a result of the increase in revenues resulting from the termination of the PPA and transition to market based rates, most or all of which is likely to be sourced to Illinois for income tax purposes, the proportion of consolidated income subject to Illinois tax is likely to increase. Similarly, the proportion of temporary differences apportioned to Illinois, for which deferred taxes are provided, is also likely to increase. Such an increase would have the effect of requiring an increase in the net state deferred income tax liability. This increased Illinois apportionment factor will be applied to Exelon’s temporary income tax differences in the period in which the new factor can be reasonably estimated, which may be in connection with the reverse-auction competitive bidding process. The increase is likely to be partially, but not wholly, offset by decreases in taxes attributable to other states. Exelon is in the process of evaluating these potential impacts on its state income tax obligations. In the course of that evaluation, Exelon will consider potential strategiesand/or alternative interpretations that it may be able to employ to mitigate these impacts. While the potential impact and mitigation strategies are still being investigated, the tax-related impacts of the auction and the reduction in sales from Generation to ComEd could have an adverse impact on Exelon’s results of operations. See Note 5 — Regulatory Issues for information regarding the reverse-auction competitive bidding process.

Pennsylvania Tax Law (Exelon and Generation)

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

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

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

Both Generation and AmerGen Energy Company, LLC (AmerGen), a wholly owned subsidiary of Generation, have a legal obligation to decommission their nuclear power plants following the expiration of their respective operating licenses. Generation and AmerGen will pay for this obligation using trust funds that have been established for this purpose. Refer to Notes 13 and 16 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for a full discussion of the accounting for nuclear decommissioning obligations, nuclear decommissioning trust funds and the corresponding accounting implications resulting from agreements entered into with ComEd and PECO at the time of the corporate restructuring effective January 1, 2001, and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Generation updates its ARO on a periodic basis. During the second quarter of 2006, Generation recorded a net decrease in the ARO of approximately $604 million and pre-tax income of $149 million resulting from revisions to estimated future nuclear decommissioning cash flows, primarily due to the following:


	•	Revised management assumptions concerning an increased likelihood of successful nuclear license renewal efforts due to an increasingly favorable environment for nuclear power and, therefore, an increased likelihood of operating the nuclear plants through a full license extension period; and

	•	A change in management’s expectation of when the U.S. Department of Energy (DOE) will establish a repository for and begin accepting spent nuclear fuel.

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


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

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

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

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

The net decrease in the ARO for the former ComEd units, the former PECO units and the AmerGen units was approximately $219 million, $183 million and $202 million, respectively. As of June 30, 2006, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2,114 million, $887 million and $433 million, respectively.

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


	Exelon and Generation

Nuclear decommissioning AROs at January 1, 2006	$	3,921
Net decrease resulting from updates to estimated future cash flows		(604	)
Accretion expense		123
Payments to decommission retired plants		(6	)

Nuclear decommissioning AROs at June 30, 2006	$	3,434

During the second quarter of 2005, Generation recorded a $281 million net decrease in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows, primarily due to ayear-over-year decline in the cost escalation factors used to estimate future undiscounted costs, partially offset by an increase resulting from

updated decommissioning cost studies received for two nuclear stations. Independent third-party appraisers provided both the updated escalation factors and the updated cost studies. There was no net impact to any of the Registrant’s Consolidated Statements of Income and Comprehensive Income resulting from the 2005 ARO update.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

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

At June 30, 2006 and December 31, 2005, both Exelon and Generation had nuclear decommissioning trust fund investments in the amounts of $5,809 million and $5,585 million, respectively.

At June 30, 2006, Exelon and Generation had gross unrealized gains of $855 million and gross unrealized losses of $63 million related to the nuclear decommissioning trust fund investments. At December 31, 2005, Exelon and Generation had gross unrealized gains of $734 million and gross unrealized losses of $47 million.

During the three and six months ended June 30, 2005, both Exelon and Generation realized gains resulting from the sale of nuclear decommissioning trust fund investments of $54 million and $55 million, respectively. Of these gains, $36 million and $39 million, in the three and six months ended June 30, 2005, respectively, related to investments held in the AmerGen decommissioning trust funds. These gains were recognized primarily as a result of changes to the investment strategy associated with the mix of investments in the nuclear decommissioning trust funds in the first half of 2005. For the former ComEd and PECO units, these gains and losses have been reflected as a component of other income and, due to the impact of regulatory accounting, had no impact on the results of operations of Exelon and Generation. See Note 14 — Supplemental Financial Information for the 2006 results.

Exelon and Generation evaluate decommissioning trust fund investments forother-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During the three and six months ended June 30, 2006, Exelon and Generation concluded that certain trust fund investments wereother-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the value of the securities and consideration of Exelon’s and Generation’s ability and intent to hold the investments until the recovery of their cost basis. This determination resulted in impairment charges of $7 million and $10 million for the three and six months ended June 30, 2006, respectively, which were recorded in other income and deductions associated with the trust funds for the decommissioning of the former ComEd plants. During the three and six months ended June 30, 2005, both Exelon and Generation recorded impairment charges of $1 million and $2 million, respectively, which were recorded in other income and deductions associated with the trust funds for the decommissioning of the AmerGen plants. Also during the three and six months ended June 30, 2005, both Exelon and Generation realized $5 million and $12 million, respectively, of the previously unrealized losses associated with the trust investments for the decommissioning of the former ComEd plants. The realization of these losses associated with the former ComEd plants had no impact on Exelon’s and Generation’s results of operations or financial position since both realized and unrealized losses are already reflected in the fair value of the investments and in the fair value of the regulatory liability at ComEd.

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

As of December 31, 2005, Exelon adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarified that a legal obligation associated with the retirement of a long-lived asset whose

timingand/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, Exelon is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated. The liabilities associated with conditional AROs will be adjusted periodically due to the passage of time, new laws and regulations, and revisions to either the timing or amount of the original estimates of undiscounted cash flows. See Note 14 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for a discussion of the accounting for non-nuclear asset retirement obligations.

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


	Exelon		ComEd		PECO		Generation

Non-nuclear AROs at January 1, 2006	$	236	$	151	$	20	$	65
Accretion expense(a)		6		4		1		1

Non-nuclear AROs at June 30, 2006	$	242	$	155	$	21	$	66


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


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

Earnings per Share

Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options outstanding under Exelon’s stock option plans considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	Three Months					Six Months
	Ended					Ended
	June 30,					June 30,
	2006		2005			2006		2005

Income from continuing operations	$	641	$	516		$	1,041	$	1,023
Income (loss) from discontinued operations		3		(2	)		3		12

Net income	$	644	$	514		$	1,044	$	1,035

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

Average common shares outstanding — diluted		676		677			675		676

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 4 million for the three and six months ended June 30, 2006. There were no stock options excluded for the three or six months ended June 30, 2005.

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. See Note 18 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for further information regarding Exelon’s share repurchase program. As of June 30, 2006, 10 million shares of common stock have been purchased under the share repurchase program for $483 million. During the six months ended June 30, 2006, Exelon repurchased 0.9 million shares of common stock under the share repurchase program for $53 million.

Other Share Repurchases

During the six months ended June 30, 2005, Exelon repurchased 0.2 million shares of common stock from a retired executive for $8 million. These repurchased shares are held as treasury shares and are recorded at cost.

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

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

Energy Commitments

Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $1.7 billion in the six months ended June 30, 2006, reflecting increases of approximately $2.2 billion and $0.5 billion in 2007 and 2008 sales commitments, respectively, primarily due to increased overall hedging activity in the normal course of business and other smaller increases in commitments in years beyond 2008, offset by the fulfillment of approximately $1.0 billion of 2006 commitments during the six months ended June 30, 2006.

Commercial Commitments

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


	•	Exelon’s letters of credit increased $61 million and guarantees (outside the scope of FIN 45) decreased $85 million primarily as a result of energy trading activities.

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

	•	Generation’s letters of credit increased $45 million and guarantees (outside the scope of FIN 45) decreased $62 million primarily as a result of energy trading activities.

Environmental Liabilities

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

sites identified by ComEd and PECO, 22 and 10 sites, respectively, are currently under some degree of active studyand/or remediation.

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

Pursuant to a PAPUC order, PECO is currently recovering a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. Based on the final order received in ComEd’s Rate Case, beginning in 2007, ComEd will also recover its MGP remediation costs from customers for which it will set up a regulatory asset (see ComEd Rate Case below). See Note 14 — Supplemental Financial Information for further information regarding regulatory assets and liabilities. As of June 30, 2006 and December 31, 2005, Exelon, ComEd, PECO and Generation had accrued the following amounts for environmental liabilities:


	Total
	Environmental
	Investigation and		Portion of Total Related
	Remediation		to MGP Investigation
June 30, 2006	Reserve		and Remediation(a)

ComEd	$	53	$	46
PECO		42		40
Generation		20		—

Exelon	$	115	$	86


(a)		Discounted.

��


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

ComEd	$	54	$	48
PECO		47		41
Generation		27		—

Exelon	$	128	$	89


(a)		Discounted.

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

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

Section 316(b) of the Clean Water Act

In July 2004, the U.S. Environmental Protection Agency (EPA) issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to, obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

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

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately

requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

Nuclear Generating Station Groundwater

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

On March 13, 2006, a class action lawsuit was filed against Exelon, Generation and ComEd (as the prior owner of Braidwood) in Federal district court for the Northern District of Illinois on behalf of all persons who live or own property within 10 miles of Braidwood. The plaintiffs primarily seek (1) a court-supervised fund for medical monitoring for risks associated with alleged exposures to tritium and (2) compensation for diminished property values. Exelon filed a motion to dismiss the case, contending that the plaintiffs cannot meet the dose threshold required to maintain a public liability action under the Price-Anderson Act. This motion was denied. On March 14 and 23, 2006, 37 area residents filed two separate but identical lawsuits against Exelon, Generation and ComEd in the Circuit Court of Will County, Illinois alleging property contamination and seeking compensation for diminished property values. Exelon removed these cases to federal court, and all three cases were assigned to the same District Court judge. Exelon has submitted its answer to the class action lawsuit; Exelon’s motions to dismiss the amended complaints in the other two lawsuits were denied in part on July 19, 2006. The court dismissed all claims premised on violations of Illinois environmental statutes. Exelon must answer the other claims by August 3, 2006. The Court has set a schedule for a class certification motion and discovery for all three suits. Generation has tendered its defense of these lawsuits to its insurance carrier, American Nuclear Insurers (ANI). Exelon, Generation and ComEd continue to believe that these lawsuits are without merit and intend to vigorously defend them.

On March 16, 2006, the Attorney General of the State of Illinois and the State’s Attorney for Will County, Illinois filed a civil enforcement action against Exelon, Generation and ComEd in the Circuit Court of Will County relating to the releases of tritium discussed above and alleging that, beginning on or before 1996, and with additional events in 1998, 2000 and 2005, there have been other non-radioactive wastes discharged from Braidwood. The action alleges violations of Braidwood’s NPDES permit, the Illinois Environmental Protection Act and regulations of the Illinois Pollution Control Board, and seeks injunctive relief, including (1) prohibiting Generation from using the line to discharge tritiated water until further court order and (2) requiring Generation to test the soil and groundwater contamination caused by the releases, implement measures to prevent future releases and the migration of contaminants already in the groundwater, and provide potable drinking water to area residents. The action also seeks the maximum civil penalties allowed by the statute and regulations, including penalties of

$10,000 or $50,000 for each violation (depending on the specific violation), and $10,000 for each day during which a violation continues. On May 11, 2006, Exelon and Generation agreed with the Illinois Attorney General, the Illinois EPA and the State’s Attorney for Will County on the terms of a preliminary injunction order that enabled Generation to commence remediation of the tritiated groundwater at Braidwood. On May 24, 2006, the Circuit Court of Will County, Illinois entered an agreed order resulting in Generation commencing remediation efforts in June 2006 according to its February 2006 proposed remediation plan for tritium in groundwater off of plant property. Among other things, the May 24 order requires Generation to conduct certain studies and implement measures to ensure that tritium does not leave plant property at levels in excess of the United States Environmental Protection Agency safe drinking water standard. Any civil penalty will not be determined until the consent decree is finalized. Generation is unable to determine the amount of the maximum penalty that is sought. Furthermore, the Circuit Court of Will County may exercise its discretion in determining the final penalty, if any, taking into account a number of factors, including corrective actions taken by Generation and other mitigating circumstances. Generation has been in continuing discussions related to this matter with the Illinois Attorney General and the State’s Attorney for Will County. Given the allegations in the lawsuit regarding the number of violations alleged and their duration, the civil penalty that could be imposed may be material to Exelon’s and Generation’s financial position, results of operations and cash flows.

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

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

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

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

In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, in the first quarter of 2006 Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to

the environment. The assessment, which is still in process and which will take place throughout 2006, has covered pipes, pumps, valves, tanks and other pieces of equipment that carry or have carried tritiated water in and around the plants. On July 31, 2006, Generation announced the preliminary results of the assessment, indicating that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood, as discussed above, where past accidental tritiated water spills have been identified and state-approved cleanup work has begun. Additional assessment work is needed to confirm these preliminary indications, but none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors. Generation management does not believe the costs of any required remediation or other additional work arising from the assessment would be material to Exelon’s or Generation’s financial position, results of operations or cash flows.

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

Cotter Corporation

The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site range up to $24 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.

Air Quality Regulation

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

Leases

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

Litigation

Exelon, PECO and Generation

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

On June 12, 2006, the five named plaintiffs filed an amended complaint and a motion seeking certification of a class comprising all white male employees of Exelon, its subsidiaries, affiliates and operating units. On behalf of the class, the plaintiffs are now seeking injunctive relief to enjoin certain of Exelon’s diversity efforts that they claim resulted in discriminatory hiring, promotion, retention, termination and compensation practices, but are seeking no monetary damages. The plaintiffs continue to seek monetary relief, including compensatory and punitive damages, only on behalf of themselves individually. On June 26, 2006, Exelon, PECO and Generation filed their response to the plaintiffs’ request for class certification, opposing such certification. On June 29, 2006, Exelon, PECO and Generation filed an answer to the amended complaint again denying all liability.

The suit has not been certified as a class action. Exelon, PECO and Generation cannot predict the outcome of this matter; however, Exelon, PECO and Generation do not expect this claim to have a material adverse effect on their financial condition, results of operations or cash flows. Management of each of Exelon, PECO and Generation believes that appropriate reserves related to this matter have been recorded.

PJM Billing Dispute. In December 2004, Exelon filed with the FERC a complaint against PJM and PPL Electric alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’s Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39.1 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

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

In an order issued March 21, 2006, FERC rejected the proposed settlement and set the matter for hearing, primarily because the proposed settlement would have required PJM market participants to bear $7.5 million of the $40.5 million settlement, plus interest. The order found that PPL should pay for energy received that was billed to other parties, but allows PPL and the market participants to question what portion of the settlement PJM might bear and what offsetting deductions might be made in reducing the payment. On March 30, 2006, Exelon and PPL filed with the FERC a second proposed settlement agreement, superceding the first, under which, if approved, Exelon would receive a total of $40.5 million, plus interest, over the next five years through credits provided by PJM, which

would be funded through a surcharge imposed by PJM through its tariff solely on PPL Electric, with no amount being paid by other PJM participants. Following FERC approval of the settlement, this amount will be collected and paid by PJM to Exelon over a five-year period with interest on the unpaid principal accruing over the collection and payment period. It is anticipated that approximately 75% and 25% of the proposed settlement amount will be received by Generation and PECO, respectively.

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

Exelon

Pension Claim. On July 11, 2006, a former employee of ComEd filed a purported class action lawsuit against the Exelon Corporation Cash Balance Pension Plan (Plan) in the Federal district court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculated lump sum distributions in a manner that does not comply with the Employee Retirement Income Security Act. The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions since 2001 and injunctive relief with respect to future lump sum distributions. Exelon is not named as a defendant in this lawsuit. It remains to be determined whether this case will proceed as a class action and how many Plan participants may be part of the proposed class, if a class is certified. Exelon believes the allegations are without merit and intends to vigorously defend this action.

ComEd

ComEd Rate Case. As part of its current Rate Case, ComEd requested recovery of amounts, which have previously been recorded as expense. Specifically, ComEd requested the following (all amounts pre-tax):


	•	recovery through rates of approximately $86 million related to losses on extinguishment of long-term debt as part of ComEd’s 2004 Accelerated Liability Management Plan;

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

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

	•	recovery of $7 million of expenses previously incurred in the Procurement Case.

As discussed in Note 5 — Regulatory Issues, ComEd received a final order from the ICC on July 26, 2006, which approved recovery of these costs. Exelon and ComEd anticipate recognizing a one-time benefit of $291 million (pre-tax) to reverse these prior charges during the third quarter of 2006.

Generation

Asbestos Claims. In the second quarter of 2005, Generation engaged independent actuaries to determine if, based on historical claims data and other available information, a reasonable estimate of future losses could be

calculated associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. Based on the actuaries’ analyses, management’s review of current and expected losses, and the view of counsel regarding the assumptions used in estimating the future losses, Generation recorded an undiscounted $43 million pre-tax charge for its estimated portion of all estimated future asbestos-related personal injury claims estimated to be presented through 2030. This amount did not include estimated legal costs associated with handling these matters, which could be material. Generation’s management determined that it was not reasonable to estimate future asbestos-related personal injury claims past 2030 based on only three years of historical claims data and the significant amount of judgment required to estimate this liability. The $43 million pre-tax charge was recorded as part of operating and maintenance expense in Generation’s Consolidated Statements of Income and Comprehensive Income in 2005 and reduced net income by $27 million after tax. See further discussion in Note 17 of Generation’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K. During the second quarter of 2006, Generation performed a periodic update to this reserve, which did not result in a material adjustment.

At June 30, 2006 and December 31, 2005, Generation had reserved approximately $48 million and $50 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2006, approximately $8 million of this amount relates to 110 open claims presented to Generation, while the remaining $40 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Generation plans to obtain annual updates of the estimate of future losses. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments.

Oil Spill Liability Trust Fund Claim. In December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River near the facilities. The units, which draw water from the river for cooling purposes, were taken offline for approximately two weeks to avoid intake of the spilled oil and for an additional two weeks relating to start up issues arising from the oil spill shut down. The total shutdown period resulted in lost sales from the plant. Generation and PSEG have filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund. As this matter represents a contingent gain, Generation has recorded no income resulting from this claim. Although no assurances can be given, Generation’s management believes it is reasonably possible that damages and losses could be recovered and that Generation’s portion of the estimated proceeds arising from the claim could be approximately $25 million. Generation expects this matter to be resolved in late 2006.

PECO and Generation

Real Estate Tax Appeals. PECO and Generation have been challenging real estate taxes assessed on certain nuclear plants. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA), and has appealed local real estate assessments for 1998 and 1999 on the Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom). Generation is involved in real estate tax appeals for 2000 through 2004 regarding the valuation of its Peach Bottom plant and is in the process of evaluating appraisals and preparing for negotiations. Generation was also previously involved in an appeal regarding the valuation of its LaSalle Nuclear plant. On March 9, 2006, the Illinois Circuit Court for LaSalle County approved the property tax settlement agreement agreed upon in late 2005 between all taxing bodies with jurisdiction over the plant and Generation. The settlement agreement resolved all pending litigation concerning assessments on the property and sets the assessments for the tax years 2005 through 2008. PECO and Generation believe their reserve balances for exposures associated with real estate taxes as of June 30, 2006 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of Exelon, PECO and Generation and such adjustments could be material.

Exelon, ComEd, PECO and Generation

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

Income Taxes

Refund Claims. ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. As of June 30, 2006, ComEd and PECO have outstanding refundable prepayments to the tax consultants of $7 million and $2 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 recovered from the IRS, if any. The ultimate net cash impacts to ComEd and PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. If a settlement is reached, a portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination” (EITF 93-7). Exelon cannot predict the timing of the final resolution of these refund claims. During the second quarter of 2006, the IRS indicated to PECO that it agreed with a substantial portion of one such refund claim. This refund claim will have to be approved by the Joint Committee on Taxation. Based on the IRS’ indication of its agreement with a portion of the refund claim, PECO recorded an estimated tax consulting contingent fee of $3 million during the second quarter of 2006.

Other Refund Claims. ComEd and PECO have filed several tax refund claims with Federal and state taxing authorities. ComEd and PECO are unable to estimate the ultimate outcome of these refund claims and will account for any amount received in the period the matters are settled with the Federal and state taxing authorities. To the extent ComEd is successful on any of its refund claims a portion of the tax and interest benefit may be recorded to goodwill under the provisions of EITF 93-7.

Other. ComEd has taken certain tax positions, which have been disclosed to the IRS to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 10 — Income Taxes for further information.


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

Supplemental Income Statement Information

The following tables provide additional information regarding the components of other, net within the Consolidated Statements of Income and Comprehensive Income of Exelon, ComEd, PECO and Generation for the three and six months ended June 30, 2006 and 2005:


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
Exelon	2006			2005			2006			2005

Investment income	$	2		$	3		$	4		$	6
Gain on disposition of assets and investments, net		(3	)		6			(2	)		7
Decommissioning-related activities:
Decommissioning trust fund income(a)		37			50			66			79
Decommissioning trust fund income — AmerGen(a)		10			47			19			59
Other-than-temporary impairment of decommissioning trust funds		(7	)		(6	)		(10	)		(14	)
Regulatory offset to non-operating decommissioning-related activities(b)		(31	)		(46	)		(57	)		(67	)
Net direct financing lease income		6			6			12			11
Allowance for funds used during construction (AFUDC), equity		—			2			—			3
Unrealized income tax credits(c)		24			—			53			—
Other		9			7			8			15

Other, net	$	47		$	69		$	93		$	99


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

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

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


	Three Months					Six Months
	Ended					Ended
	June 30,					June 30,
ComEd	2006			2005		2006			2005

Investment income	$	—		$	1	$	—		$	2
Gain (loss) on disposition of assets and investments, net		(2	)		2		(2	)		4
AFUDC, equity		—			1		—			2
Other		3			2		3			2

Other, net	$	1		$	6	$	1		$	10


	Three Months					Six Months
	Ended					Ended
	June 30,					June 30,
PECO	2006			2005		2006		2005

Investment income	$	2		$	2	$	4	$	5
Gain (loss) on disposition of assets and investments, net		(1	)		4		—		3
Other		1			—		1		1

Other, net	$	2		$	6	$	5	$	9


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
Generation	2006			2005			2006			2005

Decommissioning-related activities:
Decommissioning trust fund income(a)	$	37		$	50		$	66		$	79
Decommissioning trust fund income — AmerGen(a)		10			47			19			59
Other-than-temporary impairment of decommissioning trust funds		(7	)		(6	)		(10	)		(14	)
Contractual offset to non-operating decommissioning-related activities(b)		(31	)		(46	)		(57	)		(67	)
Other		5			6			2			12

Other, net	$	14		$	51		$	20		$	69


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

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

Supplemental Balance Sheet Information

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


	June 30,			December 31,
Exelon and ComEd	2006			2005

Regulatory assets (liabilities):
Nuclear decommissioning	$	(1,516	)	$	(1,435	)
Removal costs		(1,036	)		(1,015	)
Reacquired debt costs and interest-rate swap settlements		99			107
Conditional asset retirement obligations		95			91
Recoverable transition costs		30			43
Deferred income taxes		9			8
Other		26			31

Total net regulatory liabilities	$	(2,293	)	$	(2,170	)


	June 30,			December 31,
Exelon and PECO	2006			2005

Regulatory assets (liabilities):
Competitive transition charges	$	3,271		$	3,532
Deferred income taxes		786			781
Non-pension postretirement benefits		42			45
Reacquired debt costs		34			36
MGP remediation costs		20			26
Conditional asset retirement obligations		14			13
U.S. Department of Energy facility decommissioning		10			13
Nuclear decommissioning		(100	)		(68	)
Other		16			8

Long-term regulatory assets		4,093			4,386
Deferred (over-recovered) energy costs — current asset (liability)		(22	)		39

Total net regulatory assets	$	4,071		$	4,425

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


June 30, 2006	Exelon			ComEd		PECO		Generation

Property, plant and equipment:
Accumulated depreciation	$	8,205	(a)	$	1,334	$	2,209	$	4,518	(a)
Accounts receivable:
Allowance for uncollectible accounts		92			20		49		16


(a)		Includes accumulated amortization of nuclear fuel of $2,255 million.


December 31, 2005	Exelon			ComEd		PECO		Generation

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


(a)		Includes accumulated amortization of nuclear fuel of $2,103 million.

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


	June 30,		December 31,
Exelon and Generation	2006		2005

Other current assets:
Counterparty collateral asset	$	107	$	285
Option premiums		193		126
Other current liabilities:
Counterparty collateral liability		106		101

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

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

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

Three Months Ended June 30, 2006 and 2005

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


	ComEd		PECO		Generation			Other(a)			Eliminations			Consolidated

Total revenues(b):
2006	$	1,453	$	1,148	$	2,214		$	203		$	(1,321	)	$	3,697
2005		1,488		1,044		2,105			174			(1,327	)		3,484
Intersegment revenues:
2006	$	2	$	2	$	1,114		$	203		$	(1,321	)	$	—
2005		2		2		1,150			173			(1,327	)		—
Income (loss) from continuing operations before income taxes:
2006	$	213	$	138	$	791		$	(138	)	$	—		$	1,004
2005		180		157		482			(96	)		—			723
Income taxes:
2006	$	86	$	45	$	294		$	(62	)	$	—		$	363
2005		71		47		185			(96	)		—			207
Income (loss) from continuing operations:
2006	$	127	$	93	$	497		$	(76	)	$	—		$	641
2005		109		110		297			—			—			516
Income (loss) from discontinued operations:
2006	$	—	$	—	$	3		$	—		$	—		$	3
2005		—		—		(1	)		(1	)		—			(2	)
Net income (loss):
2006	$	127	$	93	$	500		$	(76	)	$	—		$	644
2005		109		110		296			(1	)		—			514


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


(b)		For the three months ended June 30, 2006 and 2005, utility taxes of $57 million and $57 million, respectively, are included in revenues and expenses for ComEd. For the three months ended June 30, 2006 and 2005, utility taxes of $58 million and $53 million, respectively, are included in revenues and expenses for PECO.

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


	ComEd		PECO		Generation		Other(a)			Eliminations			Consolidated

Total revenues (b):
2006	$	2,880	$	2,554	$	4,434	$	410		$	(2,719	)	$	7,559
2005		2,875		2,339		4,125		341			(2,635	)		7,045
Intersegment revenues:
2006	$	4	$	4	$	2,302	$	409		$	(2,719	)	$	—
2005		4		4		2,285		342			(2,635	)		—
Income (loss) from continuing operations before income taxes:
2006	$	304	$	279	$	1,219	$	(197	)	$	—		$	1,605
2005		297		357		977		(173	)		—			1,458
Income taxes:
2006	$	123	$	93	$	454	$	(106	)	$	—		$	564
2005		118		118		376		(177	)		—			435
Income (loss) from continuing operations:
2006	$	181	$	186	$	765	$	(91	)	$	—		$	1,041
2005		179		239		601		4			—			1,023
Income (loss) from discontinued operations:
2006	$	—	$	—	$	3	$	—		$	—		$	3
2005		—		—		15		(3	)		—			12
Net income (loss):
2006	$	181	$	186	$	768	$	(91	)	$	—		$	1,044
2005		179		239		616		1			—			1,035
Total assets:
June 30, 2006	$	17,499	$	9,723	$	17,602	$	13,567		$	(16,101	)	$	42,290

December 31, 2005		17,211		10,018		17,724		13,079			(15,583	)		42,449


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

(b)		For the six months ended June 30, 2006 and 2005, utility taxes of $119 million and $120 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2006 and 2005, utility taxes of $115 million and $105 million, respectively, are included in revenues and expenses for PECO.


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

Exelon and ComEd

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Operating revenues from affiliates
ComEd Transitional Funding Trust	$	1	$	1	$	2	$	2
Interest expense to affiliates
ComEd Transitional Funding Trust		12		17		26		36
ComEd Financing II		4		4		7		7
ComEd Financing III		3		3		6		6
Equity in losses of unconsolidated affiliates
ComEd Funding LLC		3		4		5		8


	June 30,		December 31,
	2006		2005

Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	16	$	14
Investment in affiliates
ComEd Funding LLC		11		18
ComEd Financing II		10		10
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust		13		12
Payables to affiliates (current)
ComEd Transitional Funding Trust		—		1
ComEd Financing II		6		6
ComEd Financing III		4		4
Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust		813		987
ComEd Financing II		155		155
ComEd Financing III		206		206

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Operating revenues from affiliates
Generation(a)	$	2	$	2	$	3	$	4
Other		—		—		1		—
Purchased power from affiliate
PPA with Generation(b)		685		770		1,456		1,523
Operations and maintenance from affiliates
BSC(c)		53		44		105		88
Interest income from affiliates
Exelon intercompany money pool(d)		—		1		—		3
Capitalized costs
BSC(c)		19		16		36		30
Cash dividends paid to parent		—		107		—		245


	June 30,		December 31,
	2006		2005

Receivables from affiliates (current)
Other	$	—	$	23
Receivables from affiliates (noncurrent)
Generation(e)		1,516		1,435
Payables to affiliates (current)
Generation decommissioning(f)		11		11
Generation (a),( b)		247		242
BSC(c)		21		14
Other		2		—
Borrowings from Exelon intercompany money pool(d)		—		140


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

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

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

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


(e)		ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers. See Note 11 of ComEd’s Notes to Consolidated Financial Statements within ComEd’s 2005 Annual Report onForm 10-K for additional information.

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

Exelon and PECO

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Operating revenues from affiliates
PETT(a)	$	2	$	2	$	4	$	4
Interest expense to affiliates
PETT		46		54		95		110
PECO Trust III		1		1		3		3
PECO Trust IV		2		2		3		3
Equity in losses of unconsolidated affiliates
PETT		2		4		6		8


	June 30,		December 31,
	2006		2005

Investment in affiliates
PETT	$	58	$	63
PECO Energy Capital Corp		4		4
PECO Trust IV		6		6
Payables to affiliates (current)
PECO Trust III		1		1
Long-term debt to PETT and other financing trusts (including due within one year)
PETT		2,727		2,975
PECO Trust III		81		81
PECO Trust IV		103		103


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

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Operating revenues from affiliates
Generation(a)	$	2	$	2	$	4	$	4
Purchased power from affiliate
Generation(b)		429		379		845		760
Fuel
Generation(c)		—		—		—		1
Operations and maintenance from affiliates
BSC(d)		32		28		63		53
Other		—		—		1		—
Capitalized costs
BSC(d)		12		6		29		12
Cash dividends paid to parent		135		116		251		231


	June 30,		December 31,
	2006		2005

Receivable from affiliate (current)
BSC	$	—	$	13
Contributions to Exelon intercompany money pool(e)		—		8
Receivable from affiliate (noncurrent)
Generation decommissioning(f)		100		68
Payables to affiliates (current)
Generation(b)		170		151
BSC(d)		33		26
Shareholders’ equity — receivable from parent(g)		1,161		1,232


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

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

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

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

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

(f)		PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of


		decommissioning, such amounts are due back to PECO for payment to PECO’s customers. See Note 9 of PECO’s Notes to Consolidated Financial Statements within PECO’s 2005 Annual Report onForm 10-K for additional information.

(g)		PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2006 through 2010.

Generation

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Operating revenues from affiliates
ComEd(a)	$	685	$	770	$	1,456	$	1,523
PECO(a)		429		379		845		761
BSC		—		1		1		1
Fuel from affiliate
PECO(b)		—		1		—		1
Operations and maintenance from affiliates
ComEd(b)		2		2		3		4
PECO(b)		2		1		4		3
BSC(c)		74		63		146		127
Interest expense to affiliate
Exelon intercompany money pool(d)		—		—		1		2
Cash distribution paid to member		157		80		322		319
Cash contribution received from member		—		—		—		843


	June 30,		December 31,
	2006		2005

Receivables from affiliates (current)
ComEd(a)	$	247	$	242
ComEd decommissioning(e)		11		11
PECO(a)		170		151
BSC(c)		—		7
Payables to affiliates (current)
Exelon(f)		6		4
BSC(c)		30		—
Borrowings from Exelon intercompany money pool(d)		—		92
Payables to affiliates (noncurrent)
ComEd decommissioning(g)		1,516		1,435
PECO decommissioning(g)		100		68


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

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

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

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

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

(f)		In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(g)		Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to ComEd and PECO, as applicable, for payment to the customers. See Note 13 of Generation’s Notes to Consolidated Financial Statements within Generation’s 2005 Annual Report onForm 10-K for additional information.


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

Interest-Rate Swaps (Exelon, ComEd and PECO)

The fair values of Exelon’s, ComEd’s and PECO’s interest-rate swaps are determined using quoted exchange prices, external dealer prices and available market pricing curves. At June 30, 2006, the Registrants did not have any fair-value or cash-flow hedges outstanding. At December 31, 2005, Exelon had $240 million of notional amounts of interest-rate swaps outstanding, which were held by ComEd and were settled on January 17, 2006 for a cash payment of approximately $1 million.

Fair-Value Hedges. The Registrants utilizefixed-to-floating interest-rate swaps from time to time as a means to achieve their targeted level of variable-rate debt as a percent of total debt. At June 30, 2006, the Registrants did not have any notional amounts of fair-value hedges outstanding.Fixed-to-floating interest-rate swaps are designated as fair-value hedges, as defined in SFAS No. 133 and, as such, changes in the fair value of the swaps are recorded in earnings; however, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of the swaps are offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. During the three months and six months ended June 30, 2006 and 2005, no amounts relating to fair-value hedges were recorded in earnings as a result of ineffectiveness.

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

During the three and six months ended June 30, 2005, Exelon settled interest-rate swaps in aggregate notional amounts of $1.5 billion and recorded net pre-tax losses of $39 million, which are being recorded as additional

interest expense over the remaining life of the debt. During the three and six months ended June 30, 2005, Exelon recorded income of less than $1 million which was included in other, net on Exelon’s Consolidated Statement of Income and Comprehensive Income, representing the ineffective portions of changes in the fair value of cash-flow hedge positions related to the settlement of the interest-rate swaps. During the three and six months ended June 30, 2005, ComEd did not reclassify any amounts from accumulated OCI into earnings as a result of ineffectiveness. Additionally, during the three and six months ended June 30, 2006 and 2005, Exelon and ComEd did not reclassify any amounts from accumulated OCI into earnings as a result of forecasted financing transactions no longer being probable.

Energy-Related Derivatives (Exelon, ComEd and Generation)

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

Exelon and Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts may qualify for the normal purchases and normal sales exception to SFAS No. 133. Those that do not meet the normal purchase and normal sales exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs or are designated as fair-value hedges, in which case those changes are recognized in current earnings offset by changes in the fair value of the hedged item in current earnings. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 (or are not designated as such) and proprietary trading contracts are recognized in current earnings. Generation also has contracted for access to additional generation and sales to load-serving entities that are accounted for under the accrual method of accounting discussed in Note 20 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K.

ComEd has one wholesale contract accounted for as a derivative under SFAS No. 133. This contract, which previously qualified for the normal purchase and normal sales exception pursuant to SFAS No. 133, has been recorded at fair value beginning in the first quarter of 2006 since the exception is no longer applicable. As of June 30, 2006, the fair value of this contract was recorded on Exelon’s and ComEd’s Consolidated Balance Sheets. The relatedmark-to-market loss was recorded in operating revenues within Exelon’s and ComEd’s Consolidated Statements of Income and Comprehensive Income. This contract expires in December 2007.

At June 30, 2006 Exelon, ComEd and Generation had net liabilities of $66 million, $8 million and $122 million, respectively, on their Consolidated Balance Sheets for the fair value of energy derivatives, which

included the energy derivatives at Exelon and Generation discussed below. The following table provides a summary of the fair value balances recorded by Exelon, ComEd and Generation as of June 30, 2006:


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

Current assets	$	356		$	319		$	24		$	699		$	—		$	38		$	737
Noncurrent assets		263			93			117			473			—			113			586

Totalmark-to-market energy contract assets	$	619		$	412		$	141		$	1,172		$	—		$	151		$	1,323

Current liabilities	$	(529	)	$	(327	)	$	(18	)	$	(874	)	$	(5	)	$	(6	)	$	(885	)
Noncurrent liabilities		(230	)		(74	)		(116	)		(420	)		(3	)		(81	)		(504	)

Totalmark-to-market energy contract liabilities	$	(759	)	$	(401	)	$	(134	)	$	(1,294	)	$	(8	)	$	(87	)	$	(1,389	)

Totalmark-to-market energy contract net assets (liabilities)	$	(140	)	$	11		$	7		$	(122	)	$	(8	)	$	64		$	(66	)


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

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

Cash-Flow Hedges (Generation). The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on Generation’s Consolidated Balance Sheets as of June 30, 2006. The data in the table is indicative of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all derivatives are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s derivatives. The tables also include the activity of accumulated OCI related to cash-flow hedges for the three and six months ended June 30, 2006 and 2005, providing information about the changes in the fair value of hedges and the reclassification from OCI into earnings.


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

Accumulated OCI derivative loss at April 1, 2006	$	(223	)
Changes in fair value		117
Reclassifications from OCI to net income		22

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


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

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

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


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

Accumulated OCI derivative loss at April 1, 2005	$	(259	)
Changes in fair value		(28	)
Reclassifications from OCI to net income		63

Accumulated OCI derivative loss at June 30, 2005	$	(224	)


	Total Cash-Flow
	Hedge OCI Activity,
Six Months Ended June 30, 2005	Net of Income Tax

Accumulated OCI derivative loss at December 31, 2004	$	(137	)
Changes in fair value		(204	)
Reclassifications from OCI to net income		117

Accumulated OCI derivative loss at June 30, 2005	$	(224	)

At June 30, 2006, Generation had net unrealized pre-tax losses on cash-flow hedges of $140 million in accumulated OCI. Based on market prices at June 30, 2006, approximately $173 million of these deferred net pre-tax unrealized losses on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months. However, the actual amount reclassified to earnings could vary due to future changes in market prices. Amounts recorded in accumulated OCI related to changes in energy commodity cash-flow hedges are reclassified to earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Generation’s cash-flow hedges are expected to settle within the next three years.

Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $36 million pre-tax loss and a $112 million pre-tax loss for the three and six months ended June 30, 2006, respectively, and a $102 million pre-tax loss and a $189 million pre-tax loss for the three and six months ended June 30, 2005, respectively.

Other Derivatives (Exelon, ComEd and Generation). Exelon and Generation enter into certain contracts that are derivatives, but do not qualify for hedge accounting under SFAS No. 133 or are not designated as cash-flow hedges. These contracts are also entered into to economically hedge and limit the market price risk associated with energy commodity prices. Changes in the fair value of these derivative contracts are recognized in current earnings. For the three and six months ended June 30, 2006 and 2005, Exelon, ComEd and Generation recognized the following net unrealizedmark-to-market gains (losses), realizedmark-to-market gains and totalmark-to-market gains (losses) (before income taxes) relating tomark-to-market activity of certain non-trading purchase power and sale contracts pursuant to SFAS No. 133. Generation’s, ComEd’s and Exelon’s othermark-to-market activity on

non-trading purchase power and sale contracts are reported in fuel and purchased power, revenue and operating and maintenance expense, respectively.


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

Unrealizedmark-to-market gains	$	30	$	2	$	28	$	60
Realizedmark-to-market gains		28		1		—		29

Total netmark-to-market gains	$	58	$	3	$	28	$	89


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

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


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

Unrealizedmark-to-market gains (losses)	$	(26	)	$	(9	)	$	41	$	6
Realizedmark-to-market gains		63			1			—		64

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


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

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


Three Months Ended June 30, 2005	Generation			ComEd		Other(a)		Exelon

Unrealizedmark-to-market gains (losses)	$	(28	)	$	—	$	16	$	(12	)
Realizedmark-to-market gains		7			—		—		7

Total netmark-to-market gains (losses)	$	(21	)	$	—	$	16	$	(5	)


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


Six Months Ended June 30, 2005	Generation		ComEd		Other(a)		Exelon

Unrealizedmark-to-market gains	$	25	$	—	$	16	$	41
Realizedmark-to-market gains		17		—		—		17

Total netmark-to-market gains	$	42	$	—	$	16	$	58


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

Proprietary Trading Activities (Generation). Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s Risk Management Committee. These contracts are recognized on the Consolidated Balance Sheets at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For the three and six months ended June 30, 2006 and 2005, Exelon and Generation recognized the following net unrealizedmark-to-market gains, realizedmark-to-market gains (losses) and totalmark-to-market gains (before income taxes) relating tomark-to-market activity on

derivative instruments entered into for trading purposes. Gains and losses associated with financial trading are reported as revenue in Exelon’s Consolidated Statements of Income and Comprehensive Income.


	Three Months						Six Months
	Ended						Ended
	June 30,						June 30,
	2006			2005			2006			2005

Unrealizedmark-to-market gains	$	2		$	5		$	4		$	10
Realizedmark-to-market losses		(2	)		(1	)		(4	)		(1	)

Total netmark-to-market gains	$	—		$	4		$	—		$	9

Credit Risk Associated with Derivative Instruments (Exelon and Generation)

Exelon would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Exelon’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.


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

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

General

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


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

	•	PECO,whose businesses include the purchase and regulated retail sale of electricity and distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

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

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

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

EXELON CORPORATION

Executive Overview

Financial Results. Exelon’s net income was $644 million for the three months ended June 30, 2006 as compared to $514 million for the same period in 2005 and diluted earnings per average common share were $0.95 for the three months ended June 30, 2006 as compared to $0.76 for the same period in 2005.

Exelon’s net income was $1,044 million for the six months ended June 30, 2006 as compared to $1,035 million for the same period in 2005 and diluted earnings per average common share were $1.55 for the six months ended June 30, 2006 and $1.53 for the same period in 2005.

The increase for both the three and six month periods ended June 30, 2006 was primarily due to the following:


	•	higher margins on Generation’s wholesale market sales;

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

	•	unrealizedmark-to-market gains on contracts not yet settled;

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

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

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

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


	•	unfavorable weather conditions in Exelon’s service territories;

	•	reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset;


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

	•	higher operating and maintenance expenses, including expenses related to stock-based compensation as a result of adopting FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R) and the impacts of inflation;

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

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

Investment Strategy. Exelon continues to follow a disciplined approach in investing to maximize earnings and cash flows from its assets and businesses, while selling those investments that do not meet its strategic goals. Highlights from the six months ended June 30, 2006 include the following:


	•	Proposed Merger with Public Service Enterprise Group Incorporated (PSEG) — On December 20, 2004, Exelon entered into a merger agreement with PSEG (Merger). On May 30, 2006, the Nuclear Regulatory Commission approved the Merger and transfer of the nuclear plant operating licenses from PSEG Nuclear to Generation.

On June 22, 2006, Exelon and PSEG reached a comprehensive agreement with the Antitrust Division of the United States Department of Justice (DOJ), which resolves all competition issues reviewed by the DOJ in connection with the proposed Merger. Under the terms of the DOJ agreement, Exelon and PSEG will divest fossil-fuel fired electric generating stations with a total capacity of approximately 5,600 megawatts. The divestitures will be required when the Merger closes.

The New Jersey Board of Public Utilities (NJBPU) is the only remaining regulatory authority whose approval is required to complete the Merger. Settlement discussions are continuing with the NJBPU staff and other parties. Exelon and PSEG recently made an enhanced settlement proposal that includes concessions that are significantly greater than the concessions originally offered. Exelon and PSEG have also indicated that it is essential to reach a settlement promptly. If Exelon and PSEG are able to reach a settlement in New Jersey, the settlement would need to be reviewed by the administrative law judge presiding over the case and would need to be approved by the NJBPU after public comment. Although it is possible that this process could be completed in time to allow the Merger to close in the third quarter of 2006, there is currently no established timetable for NJBPU action on the Merger. The final decision on whether to proceed with the Merger will rest with the boards of both Exelon and PSEG after the terms and conditions of regulatory requirements are known.

Financing Activities. During the six months ended June 30, 2006, Exelon met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including capital markets, and through bank borrowings. In February 2006, ComEd and Generation entered into credit facilities totaling $1 billion and $950 million, respectively. In addition, in March 2006, ComEd issued $325 million of First Mortgage Bonds. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information on the credit facilities and the bond issuance.

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


	•	ComEd Procurement Filing — On January 24, 2006, the Illinois Commerce Commission (ICC) approved ComEd’s procurement case, authorizing ComEd to procure power after 2006 through a “reverse-auction” competitive bidding process and to recover the costs from retail customers with no markup. The first auction is scheduled to take place in September. The ICC order is being appealed.

	•	ComEd Rate Case (Rate Case) — In 2005, ComEd made a rate case filing seeking to review its tariff and to adjust ComEd’s rates for delivering electricity to users in its service area, effective January 2007, in order to reflect ComEd’s rising costs and significant capital investment in its delivery system. ComEd proposed a

revenue increase of $317 million. On June 8, 2006, the administrative law judges issued a proposed order, which included a revenue increase of $164 million plus ComEd’s request for recovery of several items which previously were recorded as expense. On July 26, 2006, the ICC issued its order in the Rate Case which approved a revenue increase of $8 million. The ICC order did approve ComEd’s requested recovery of several items, which previously were recorded as expense, including severance costs, debt extinguishment costs and manufactured gas plant (MGP) remediation costs. However, the ICC disallowed rate base treatment (return) for ComEd’s prepaid pension asset, net of deferred taxes, of $639 million. This disallowance will not result in an immediate write-off since the pension asset will be recovered as pension cost is recognized and recovered from customers in the future but will reduce ComEd’s future return on equity until the asset is recovered. The ICC order is subject to rehearing and appeal. ComEd believes that the disallowances contained in the order are inappropriate and intends to vigorously pursue these issues on rehearing and appeal. ComEd may incur an impairment charge associated with its goodwill in the third quarter due to the ICC order. As of June 30, 2006, Exelon and ComEd have goodwill of approximately $3.5 billion. Under GAAP, goodwill is tested for impairment at least annually or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill may be impaired. ComEd currently performs its annual test in the fourth quarter of each year. However, due to the significant negative impact of the ICC’s order to the cash flows and value of ComEd, it is required to complete an interim impairment test during the third quarter of this year. The interim test may lead to an impairment of goodwill at both Exelon and ComEd. The size of any potential impairment will not be known until ComEd completes its test in the third quarter but any impairment could be material.


	•	ComEd Residential Rate Stabilization — On May 23, 2006, ComEd filed a residential rate stabilization proposal to ease residential customers’ transition after 2006 to cost-based rates from frozen rates, which would require regulatory approval to implement. Under the proposal, residential rate increases would be capped at 8% in 2007, an additional 7% in 2008 and an additional 6% in 2009. Costs that exceed the caps would be deferred and recovered with carrying charges over three years from 2010 to 2012. The plan would terminate under a force majeure event or if ComEd’s senior unsecured credit rating for at least one of the three major credit rating agencies falls below investment grade. ComEd is reviewing this initiative in light of the ICC order in the Rate Case.

	•	Nuclear Fleet Inspection — In February 2006, Exelon and Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium into the environment. The initiative is in response to the detection of tritium in water samples taken related to leaks at the Braidwood, Byron and Dresden nuclear generating stations in Illinois. There is no health or safety threat to existing drinking water wells or sources based on current testing results, and the drinking water tested in residential wells meets federal safe drinking water standards. Exelon and Generation continue to monitor these matters and are working with state and local officials to determine the appropriate remediation plans, where necessary. As part of an agreement Exelon and Generation reached in May 2006 with the Illinois Attorney General, Will County State’s Attorney and Illinois Environmental Protection Agency, in June 2006, Generation began remediation of the contaminated groundwater at Braidwood. The remediation program could take 12 months or longer to complete.

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


	•	Exelon expects the Merger will result in synergies, cost savings and operating efficiencies. Although Exelon expects to achieve these anticipated benefits of the Merger, achieving them is subject to a number of uncertainties.

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


		through the costs of that energy to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction competitive bidding process.


	•	The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. Generally, between 60% and 70% of Generation’s supply currently serves ComEd and PECO customers. Consequently, Generation has historically limited its earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations. Following the expiration of the purchased power agreement (PPA) with ComEd at the end of 2006, approximately 70% to 80% of Generation’s supply will be exposed to energy market prices, increasing the volatility of Exelon’s results. The PPA between Generation and PECO expires at the end of 2010. Current market prices for electricity have increased significantly over the past few years due to the rise in natural gas and fuel prices. As a result, Generation’s margins have improved due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants. As mentioned previously, following the expiration of the PPA between ComEd and Generation, Exelon will increase the amount of power sold into the wholesale energy market. Based on recent increases in market prices, power now being sold to ComEd is likely to be sold in 2007 at higher prices than the prices previously received as part of the PPA.

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

	•	Select northeast and mid-Atlantic states are currently developing a model rule, via the Regional Greenhouse Gas Initiative (RGGI), to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federaland/or state legislation to regulate carbon emissions could occur in the future. If these plans become effective, Exelon may incur costs to either further limit the emissions from certain of its fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies. However, Exelon may benefit from stricter emission standards due to its significant nuclear capacity, which is not anticipated to be affected by the proposed emission standards.

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

	•	Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. The IRS provides tax credits for such facilities under Section 45k (formerly Section 29) of the Internal Revenue Code. The operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006 primarily due to the level and volatility of oil prices. If oil prices continue to increase from current levels, Exelon may no longer earn tax credits related to the investments for the remainder of 2006 and 2007. However, Exelon is anticipating to generate approximately $120 million of cash over the life of these investments. See Note 10 of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources for further discussion.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s 2005 Annual Report onForm 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for asset

retirement obligations, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement welfare benefits, regulatory accounting, derivative instruments, contingencies, severance and revenue recognition.

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

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

Goodwill (Exelon and ComEd)

As of June 30, 2006, Exelon and ComEd had approximately $3.5 billion of goodwill, which related entirely to the goodwill recorded upon the acquisition of ComEd. Exelon and ComEd perform assessments for impairment of their goodwill at least annually, or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired. Application of the goodwill impairment test requires significant management judgments, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit. Exelon assesses goodwill impairment at its ComEd reporting unit; accordingly, any goodwill impairment charge at ComEd is fully reflected in Exelon’s results of operations.

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

New Accounting Pronouncements

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

Results of Operations — Exelon Corporation

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


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

Operating revenues	$	3,697		$	3,484		$	213
Operating expenses
Purchased power and fuel expense		1,073			1,156			83
Operating and maintenance expense		881			929			48
Depreciation and amortization		371			325			(46	)
Taxes other than income		170			177			7

Total operating expenses		2,495			2,587			92

Operating income		1,202			897			305
Other income and deductions		(198	)		(174	)		(24	)

Income from continuing operations before income taxes		1,004			723			281
Income taxes		363			207			(156	)

Income from continuing operations		641			516			125
Income (loss) from discontinued operations, net of income taxes		3			(2	)		5

Net income	$	644		$	514		$	130

Diluted earnings per share	$	0.95		$	0.76		$	0.19

Net Income. Exelon’s net income for the three months ended June 30, 2006 reflects higher realized prices on market sales and increased nuclear output at Generation; a decrease in Generation’s nuclear asset retirement obligation (ARO) resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily AmerGen nuclear plants; unrealizedmark-to-market gains; increased electric revenues at PECO associated with certain authorized rate increases; and increased kWh deliveries, excluding the effects of weather, reflecting load growth at ComEd and PECO. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories; reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset; increased depreciation and amortization expense, including CTC amortization at PECO; and higher operating and maintenance expenses due to impacts of inflation and increased stock-based compensation expense as a result of adoptingSFAS No. 123-R. Exelon’s net income for the three months ended June 30, 2005 reflected a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims; unrealizedmark-to-market losses; and gains realized in 2005 on AmerGen’s decommissioning trust fund investments related to changes in the investment strategy.

Operating Revenues. Operating revenues increased primarily due to an increase in wholesale and retail electric sales and retail gas sales at Generation due to an increase in market prices; higher kWh deliveries at ComEd and PECO, excluding the effects of weather; and electric rate increases at PECO. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased due to lower volumes of power purchased in the market and decreased fossil generation, partially offset by overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 17% of Generation’s total supply for the three months ended June 30, 2006 compared to 19% for the three months ended June 30, 2005. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense decreased primarily due to the impact of the reduction in Generation’s nuclear asset retirement obligation and a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims, partially offset by the impairment of the intangible asset associated with the investments in synthetic fuel-producing facilities of $115 million; inflation;mark-to-market gains associated with Exelon’s investment in synthetic fuel-producing facilities; and expenses related to stock-based compensation as a result of adoptingSFAS No. 123-R. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO and additional plant placed in service.

Taxes Other Than Income. Taxes other than income decreased due to favorable state franchise tax settlements at PECO in 2006.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 36.2% for the three months ended June 30, 2006 compared to 28.6% for the three months ended June 30, 2005. The increase in the income tax rate is primarily due to the phase-out of the income tax credits associated with Exelon’s investments in synthetic fuel-producing facilities. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, Exelon has sold or wound down substantially all components of Enterprises. Accordingly, the results of operations and any gain or loss on the sale of these entities have been presented as discontinued operations within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Income and Comprehensive Income. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations. The results of Sithe are included in the Generation discussion below.

The income from discontinued operations increased by $5 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005 primarily due to an adjustment to the gain on the sale of Sithe as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the three months ended June 30, 2006 compared to the same period in 2005 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Income from Continuing Operations by Business Segment


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

ComEd	$	127		$	109	$	18
PECO		93			110		(17	)
Generation		497			297		200
Other(a)		(76	)		—		(76	)

Total	$	641		$	516	$	125


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

Net Income by Business Segment


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

ComEd	$	127		$	109		$	18
PECO		93			110			(17	)
Generation		500			296			204
Other(a)		(76	)		(1	)		(75	)

Total	$	644		$	514		$	130


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

Results of Operations — ComEd


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

Operating revenues	$	1,453		$	1,488		$	(35	)
Operating expenses
Purchased power		766			858			92
Operating and maintenance		218			202			(16	)
Depreciation and amortization		106			101			(5	)
Taxes other than income		71			73			2

Total operating expenses		1,161			1,234			73

Operating income		292			254			38

Other income and deductions
Interest expense		(77	)		(77	)		—
Equity in losses of unconsolidated affiliates		(3	)		(4	)		1
Other, net		1			7			(6	)

Total other income and deductions		(79	)		(74	)		(5	)

Income before income taxes		213			180			33
Income taxes		86			71			(15	)

Net income	$	127		$	109		$	18

Net Income. ComEd’s net income for the three months ended June 30, 2006 compared to the same period in 2005 reflects lower purchased power due to lower prices in ComEd’s PPA with Generation partially offset by lower operating revenues and higher operating and maintenance expenses as more fully described below.

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


	Increase
	(Decrease)

Weather	$	(71	)
Customer choice		(16	)
Volume		22
Rate changes and mix		21

Retail revenue		(44	)

Wholesale and miscellaneous revenues		6
Mark-to-market wholesale contract		3

Decrease in operating revenues	$	(35	)

Weather. The amount of revenues attributable to weather conditions was lower due to unfavorable weather conditions for the three months ended June 30, 2006 compared to the same period in 2005. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather in non-summer months reduces demand. In ComEd’s service territory, heating degree days were 7% lower and cooling degree days were 32% lower, during the three months ended June 30, 2006 compared to the same period in 2005.

Customer choice. For the three months ended June 30, 2006 and 2005, 31% and 36%, respectively, of energy delivered to ComEd’s retail customers was provided by alternative electric suppliers or under the Power Purchase Option (PPO).

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


	Three Months Ended June 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)		5,063			4,825
Percentage of total retail deliveries		24	%		22	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end		16,100			22,300
Percentage of total retail customers		(b	)		(b	)
Volume (GWhs)(a)		6,552			7,893
Percentage of total retail deliveries		31	%		36	%


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

(b)		Less than one percent.

Volume. The amount of revenues attributable to volume was higher for the three months ended June 30, 2006 compared to the same period in 2005 due primarily to an increase in residential deliveries excluding the effects of weather due to increased customers and increased usage per customer.

customers is dependent on the amount and time of day that the power was consumed. Changes in customer consumption patterns, including increased usage, can result in an overall decrease in the average rate even though the tariff or rate schedule remains unchanged.

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

Mark-to-market wholesale contract. Market-to-market wholesale revenues reflect amark-to-market increase associated with one wholesale contract that had previously been recorded as a normal sale under FAS 133 in 2005. This contract expires in December 2007.

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


	Increase
	(Decrease)

Prices	$	(54	)
Weather		(37	)
Customer choice		(19	)
PJM Interconnection, LLC (PJM) transmission		(1	)
Volume		15
SECA rates		6
Other		(2	)

Decrease in purchased power expense	$	(92	)

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

Weather. The decrease in purchased power expense attributable to weather was due to unfavorable weather conditions in the ComEd service territory, which decreased the amount of electricity sold.

Customer choice. The decrease in purchased power expense from customer choice was primarily due to fewer ComEd non-residential customers electing the ComEd PPO.

PJM transmission. The decrease in PJM transmission expense reflects a decrease in ancillary charges partially offset by increased peak and kWh consumption by ComEd-supplied customers due to load growth as well as an increase in ComEd-supplied customers driven by more customers choosing ComEd for supply due to alternative suppliers’ higher market prices.

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

Seams Elimination Charge/Cost Adjustment/Assignment (SECA) rates. Effective December 1, 2004, PJM became obligated to pay SECA collections to ComEd and ComEd became obligated to pay SECA charges. These charges were being collected subject to refund as they are being disputed. ComEd recorded SECA collections and payments on a net basis through purchased power expense. As ComEd was a net collector of SECA charges, the 2005 purchased power expense was lower than 2006 due to the expiration of SECA charges. SECA charges expired on March 31, 2006. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

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


	Increase
	(Decrease)

Corporate allocations	$	6
Wages and salaries		4
Fringe benefits(a)		3
Severance-related expenses		3
PSEG merger integration costs		2
Other		(2	)

Increase in operating and maintenance expense	$	16


(a)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $6 million offset by decreased pension and other postretirement benefits costs of $3 million.

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


	Increase
	(Decrease)

Depreciation expense associated with higher plant balances	$	3
Other amortization expense		2

Increase in depreciation and amortization expense	$	5

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


	Increase
	(Decrease)

Real estate taxes	$	(3	)
Other		1

Decrease in taxes other than income	$	(2	)

Interest Expense. Interest expense remained constant for the three months ended June 30, 2006 compared to 2005.

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


	Increase
	(Decrease)

Gain (loss) on disposal of assets and investments, net	$	(4	)
Other		(2	)

Decrease in other, net	$	(6	)

Income Taxes. The effective income tax rate was 40.4% for the three months ended June 30, 2006 compared to 39.4% for the three months ended June 30, 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

ComEd Electric Operating Statistics and Revenue Detail


	Three Months
	Ended June 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		6,124		6,235		(111	)		(1.8	)%
Small commercial & industrial		5,709		5,103		606			11.9	%
Large commercial & industrial		2,430		2,103		327			15.5	%
Public authorities & electric railroads		514		521		(7	)		(1.3	)%

Total full service		14,777		13,962		815			5.8	%

PPO
Small commercial & industrial		814		1,433		(619	)		(43.2	)%
Large commercial & industrial		675		1,635		(960	)		(58.7	)%

		1,489		3,068		(1,579	)		(51.5	)%

Delivery only(b)
Small commercial & industrial		1,291		1,495		(204	)		(13.6	)%
Large commercial & industrial		3,772		3,330		442			13.3	%

		5,063		4,825		238			4.9	%

Total PPO and delivery only		6,552		7,893		(1,341	)		(17.0	)%

Total retail deliveries		21,329		21,855		(526	)		(2.4	)%


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

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


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

Full service(a)
Residential	$	547	$	559	$	(12	)		(2.1	)%
Small commercial & industrial		452		413		39			9.4	%
Large commercial & industrial		130		105		25			23.8	%
Public authorities & electric railroads		32		32		—			—

Total full service		1,161		1,109		52			4.7	%

PPO(b)
Small commercial & industrial		61		99		(38	)		(38.4	)%
Large commercial & industrial		42		93		(51	)		(54.8	)%

		103		192		(89	)		(46.4	)%

Delivery only(c)
Small commercial & industrial		21		27		(6	)		(22.2	)%
Large commercial & industrial		40		41		(1	)		(2.4	)%

		61		68		(7	)		(10.3	)%

Total PPO and delivery only		164		260		(96	)		(36.9	)%

Total electric retail revenues		1,325		1,369		(44	)		(3.2	)%
Wholesale and miscellaneous revenue(d)		125		119		6			5.0	%
Mark-to-market wholesale contract		3		—		3			n.m.

Total operating revenues	$	1,453	$	1,488	$	(35	)		(2.4	)%


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

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

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

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

n.m. Not meaningful

Results of Operations — PECO


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

Operating revenues	$	1,148		$	1,044		$	104
Operating expenses
Purchased power and fuel		577			503			(74	)
Operating and maintenance		141			119			(22	)
Depreciation and amortization		172			137			(35	)
Taxes other than income		53			60			7

Total operating expenses		943			819			(124	)

Operating income		205			225			(20	)

Other income and deductions
Interest expense		(67	)		(70	)		3
Equity in losses of unconsolidated affiliates		(2	)		(4	)		2
Other, net		2			6			(4	)

Total other income and deductions		(67	)		(68	)		1

Income before income taxes		138			157			(19	)
Income taxes		45			47			2

Net income		93			110			(17	)
Preferred stock dividends		1			1			—

Net income on common stock	$	92		$	109		$	(17	)

Net Income. PECO’s net income for the three months ended June 30, 2006 compared to the same period in 2005 decreased primarily due to higher CTC amortization and higher operating and maintenance expense, partially offset by higher revenues, net of purchased power and fuel expense. Higher net revenues reflected certain authorized electric rate increases, including a scheduled CTC rate increase, partially offset by lower net electric and gas revenues as a result of unfavorable weather. The increases in CTC amortization expense and CTC rates are in accordance with PECO’s 1998 restructuring settlement with the Pennsylvania Public Utility Commission (PAPUC). The increase in CTC amortization expense exceeded the increase in CTC revenues.

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


							Total
							Increase
	Electric			Gas			(Decrease)

Rate increases	$	59		$	26		$	85
Customer choice		16			—			16
Volume		15			(1	)		14
Other rate changes and mix		9			—			9
Weather		(10	)		(17	)		(27	)

Retail revenue		89			8			97

Miscellaneous revenues		7			—			7

Increase in operating revenues	$	96		$	8		$	104

Rate increases. The increase in electric revenues attributable to electric rate increases reflects scheduled CTC and energy rate increases in accordance with PECO’s 1998 restructuring settlement with the PAPUC and the elimination of the aggregate $200 million electric distribution rate reductions over the period January 1, 2002 through December 31, 2005 ($40 million in 2005) related to the PAPUC’s approval of the merger between PECO and ComEd. The increase in gas revenues was due to increases in rates through PAPUC-approved changes to the purchased gas adjustment clause that became effective June 1, 2005 and December 1, 2005, partially offset by subsequent decreases in rates effective March 1, 2006 and June 1, 2006. The average purchased gas cost rate per million cubic feet in effect for the three months ended June 30, 2006 was 38% higher than the average rate for the same period in 2005.

Customer choice. For the three months ended June 30, 2006 and 2005, 2% and 6%, respectively, of energy delivered to PECO’s retail customers was provided by alternative electric suppliers.

All PECO customers have the choice to purchase energy from an alternative electric supplier. This choice does not affect the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. Operating income is not affected by customer choice since any increase or decrease in revenues is completely offset by any related increase or decrease in purchased power expense.


	Three Months Ended June 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end		38,300			71,200
Percentage of total retail customers		3	%		5	%
Volume (GWhs)(a)		188			535
Percentage of total retail deliveries		2	%		6	%


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

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

Volume. The increase in electric revenues as a result of higher delivery volume, exclusive of the effects of weather and customer choice, was primarily due to an increased number of customers and increased usage across all customer classes. The decrease in gas revenues attributable to lower delivery volume, exclusive of the effects of weather, was due to decreased customer usage, which is consistent with the impact of rising gas prices.

Other rate changes and mix. The increase in electric revenues attributable to other rate changes and mix was primarily due to higher rates for certain large commercial and industrial customers whose rates reflect wholesale energy prices, which were higher in 2006 relative to 2005.

Weather. The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity and gas. Conversely, mild weather reduces demand. Revenues were negatively affected by unfavorable weather conditions in PECO’s service territory, where heating degree days were 31% lower during the three months ended June 30, 2006 compared to the same period in 2005. Cooling degree days were the same for both periods.

Miscellaneous revenues. Miscellaneous electric revenues increased primarily due to increased PJM transmission revenue.

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


							Total
							Increase
	Electric			Gas			(Decrease)

Prices	$	41		$	26		$	67
Customer choice		16			—			16
PJM transmission		8			—			8
Volume		5			(1	)		4
Weather		(4	)		(14	)		(18	)
Other		(2	)		(1	)		(3	)

Increase in purchased power and fuel expense	$	64		$	10		$	74

Prices. PECO’s purchased power expense increased $22 million corresponding to the increase in electric revenues which was attributable to the scheduled energy rate increase. In addition, PECO’s purchased power expense increased $19 million due to a change in the mix of average pricing related to its PPA with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

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

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

Volume. The increase in purchased power expense attributable to volume, exclusive of the effects of weather and customer choice, was primarily due to an increased number of customers and increased usage across all customer classes. The decrease in gas fuel expense attributable to volume, exclusive of the effects of weather, was due to decreased customer usage, which is consistent with rising gas prices.

Weather. The decrease in purchased power and fuel expense attributable to weather was primarily due to lower demand due to unfavorable weather conditions in the PECO service territory.

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


	Increase
	(Decrease)

Contractors(a)	$	11
Allowance for uncollectible accounts(b)		7
Fringe benefits(c)		4
PSEG merger integration costs		1
Implementation of new customer information and billing system		(2	)
Other		1

Increase in operating and maintenance expense	$	22


(a)		Reflects higher professional fees associated with tax consulting and various other increases.

(b)		Reflects the following factors, all of which increased expense in 2006 as compared to 2005: (i) higher accounts receivable balances in 2006 compared to 2005 resulting from increased revenues; (ii) changes in PAPUC-approved regulations which relaxed customer payment terms; and (iii) an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables.

(c)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $2 million.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the three months ended June 30, 2006 compared to the same period in 2005 was due to the increase in CTC amortization of $35 million. PECO’s additional amortization of the CTC is in accordance with its original settlement under the Pennsylvania Competition Act.

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


	Increase
	(Decrease)

State franchise tax adjustment in 2006(a)	$	(7	)
Sales and use tax adjustment in 2006(a)		(5	)
Taxes on utility revenues(b)		5

Decrease in taxes other than income	$	(7	)


(a)		Represents the reduction of tax accruals in the second quarter of 2006 following settlements related to prior year tax assessments.

(b)		As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in tax expense was offset by a corresponding increase in revenues.

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

Other, Net. The decrease was primarily due to gains on disposition of assets of $4 million in 2005.

Income Taxes. The effective income tax rate was 32.6% for the three months ended June 30, 2006 compared to 29.9% for the three months ended June 30, 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail

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


	Three Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		2,719		2,686		33			1.2	%
Small commercial & industrial		1,869		1,730		139			8.0	%
Large commercial & industrial		3,875		3,705		170			4.6	%
Public authorities & electric railroads		229		205		24			11.7	%

Total full service		8,692		8,326		366			4.4	%

Delivery only(b)
Residential		14		74		(60	)		(81.1	)%
Small commercial & industrial		163		315		(152	)		(48.3	)%
Large commercial & industrial		11		146		(135	)		(92.5	)%

Total delivery only		188		535		(347	)		(64.9	)%

Total retail deliveries		8,880		8,861		19			0.2	%


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

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


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

Full service(a)
Residential	$	392	$	359	$	33			9.2	%
Small commercial & industrial		236		203		33			16.3	%
Large commercial & industrial		319		283		36			12.7	%
Public authorities & electric railroads		22		19		3			15.8	%

Total full service		969		864		105			12.2	%

Delivery only(b)
Residential		1		6		(5	)		(83.3	)%
Small commercial & industrial		9		17		(8	)		(47.1	)%
Large commercial & industrial		1		4		(3	)		(75.0	)%

Total delivery only		11		27		(16	)		(59.3	)%

Total electric retail revenues		980		891		89			10.0	%

Miscellaneous revenues(c)		60		53		7			13.2	%

Total electric and other revenue	$	1,040	$	944	$	96			10.2	%


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

(b)		Delivery only revenue reflects revenue from customers receiving generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(c)		Miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

PECO Gas Sales Statistics and Revenue Detail

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


	Three Months
	Ended
	June 30,
Deliveries to customers (in million cubic feet (mmcf))	2006		2005		Variance			% Change

Retail sales		6,292		7,398		(1,106	)		(14.9	)%
Transportation		6,139		6,019		120			2.0	%

Total		12,431		13,417		(986	)		(7.3	)%


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

Retail sales	$	103	$	95	$	8		8.4	%
Transportation		4		4		—		0.0	%
Resales and other		1		1		—		0.0	%

Total gas revenue	$	108	$	100	$	8		8.0	%

Results of Operations — Generation


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

Operating revenues	$	2,214		$	2,105		$	109
Operating expenses
Purchased power and fuel		843			945			102
Operating and maintenance		440			602			162
Depreciation and amortization		72			63			(9	)
Taxes other than income		41			39			(2	)

Total operating expenses		1,396			1,649			253

Operating income		818			456			362

Other income and deductions
Interest expense		(40	)		(29	)		(11	)
Equity in gains (losses) of unconsolidated affiliates		(1	)		4			(5	)
Other, net		14			51			(37	)

Total other income and deductions		(27	)		26			(53	)

Income from continuing operations before income taxes		791			482			309
Income taxes		294			185			(109	)

Income from continuing operations		497			297			200
Income from discontinued operations, net of income taxes		3			(1	)		4

Net income	$	500		$	296		$	204

Net Income. Generation’s net income for the three months ended June 30, 2006 compared to the same period in 2005 increased due to higher revenue, net of purchased power and fuel expense and lower operating and maintenance expense, partially offset by lower other income and deductions. The increase in Generation’s revenue, net of purchased power and fuel expense, is related to realized revenues associated with forward sales entered into in prior periods which were recognized at higher prices and the impact of higher nuclear output. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. The decrease in operating and maintenance expense is primarily due to the recognition of operating income in the second quarter of 2006 associated with the reduction in the nuclear ARO.

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


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

Electric sales to affiliates	$	1,098	$	1,133	$	(35	)		(3.1	)%
Wholesale and retail electric sales		943		783		160			20.4	%

Total energy sales revenue		2,041		1,916		125			6.5	%

Retail gas sales		91		95		(4	)		(4.2	)%
Trading portfolio		3		3		—			n.m.
Other revenue(a)		79		91		(12	)		(13.2	)%

Total revenue	$	2,214	$	2,105	$	109			5.2	%


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


		n.m. Not meaningful


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

Electric sales to affiliates		27,947		28,582		(635	)		(2.2	)%
Wholesale and retail electric sales		18,744		18,410		334			1.8	%

Total sales		46,691		46,992		(301	)		(0.6	)%

Trading volumes of 7,769 GWhs and 5,660 GWhs for the three months ended June 30, 2006 and 2005, respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $35 million for the three months ended June 30, 2006 compared to the same period in 2005. The decrease in revenue from sales to affiliates was primarily due to a $23 million decrease from lower electric sales volume, and lower prices resulting in a $12 million decrease in revenues. In the ComEd territories, lower volumes as a result of milder weather quarter over quarter and fewer customers electing an alternative electric supplier resulted in a $36 million decrease in revenues. In addition, prices were lower as a result of lower peak prices in the purchased power agreement resulting in a $49 million decrease in revenues. Beginning in 2007, the PPA with ComEd will expire and be replaced with a reverse-auction bidding process approved by the ICC. In the PECO territories, the higher volumes attributable to higher usage and more customers resulted in increased revenues of $13 million. The remaining $37 million increase is a result of a change in the mix of average pricing related to the PPA with PECO.

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


	Increase
	(Decrease)

Price	$	146
Volume		14

Increase in wholesale and retail electric sales	$	160

Wholesale and retail electric sales increased $160 million due to realized revenues associated with forward sales entered into in prior periods, which were recognized at higher prices for the three months ended June 30, 2006 compared to the same period in 2005. In addition, higher volumes of generation capacity were sold to the market in 2006 as compared to 2005. Generation had more power to sell into the market as a result of strong unit performance and less demand for power sold to affiliates for the three months ended June 30, 2006.

Retail gas sales. Retail gas sales decreased $4 million primarily due to lower gas volumes partially offset by higher realized prices.

Other revenues. The decrease in other revenues for the three months ended June 30, 2006 compared to the same period in 2005 was primarily due to a decrease in volumes associated with fossil fuel sales.

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


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

Nuclear generation(a)		35,442		34,685		757			2.2	%
Purchases — non-trading portfolio		8,101		9,061		(960	)		(10.6	)%
Fossil and hydroelectric generation		3,148		3,246		(98	)		(3.0	)%

Total supply		46,691		46,992		(301	)		(0.6	)%


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

The changes in Generation’s purchased power and fuel expense for the three months ended June 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Price	$	54
Volume		(76	)
Mark-to-market		(80	)

Decrease in purchased power and fuel expense	$	(102	)

Price. Generation experienced overall higher market energy prices for purchased power in 2006 compared to the prior year, which was partially offset by Generation’s forward sales hedging program. Energy market conditions resulted in overall higher prices for raw materials (e.g., oil, gas and coal) used in the production of electricity. In addition, realized prices for retail gas contributed to increased expenses.

Volume. The decreased volume for the three months ended June 30, 2006 as compared to the same period in 2005 was primarily due to lower volumes of power purchased in the market and decreased fossil generation and retail gas purchases, slightly offset by higher nuclear and hydroelectric generation.

Mark-to-market. Mark-to-market gains on hedging activities were $58 million for the three months ended June 30, 2006 compared to losses of $22 million for the same period in 2005.

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


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

Average electric revenue
Electric sales to affiliates	$	39.29	$	39.64		(0.9	)%
Wholesale and retail electric sales		50.31		42.53		18.3	%
Total — excluding the trading portfolio		43.71		40.77		7.2	%
Average electric supply cost (a) — excluding the trading portfolio		16.04		18.17		(11.7	)%
Average margin — excluding the trading portfolio		27.67		22.60		22.4	%


(a)		Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales and other sales.

Nuclear fleet operating data for the three months ended June 30, 2006 and 2005 were as follows:


	Three Months
	Ended
	June 30,
	2006			2005

Nuclear fleet capacity factor(a)		95.5	%		95.4	%
Nuclear fleet production cost per MWh(a)	$	12.94		$	11.93


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor increased due to fewer planned refueling outage days and fewer non-refueling outage days during the three months ended June 30, 2006 compared to the same period in 2005. For the three months ended June 30, 2006 and 2005, refueling outage days totaled 35 and 36, respectively. Total non-refueling outage days for the three months ended June 30, 2006 and 2005 were 24 and 26, respectively. Higher costs for nuclear fuel

amortization and inspection and maintenance costs for non-refueling outages, a Nuclear Regulatory Commission (NRC) fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated resulting in a higher production cost per MWh produced for the three months ended June 30, 2006 as compared to the same period in 2005. There was one planned refueling outage and three non-refueling outages that began during the three months ended June 30, 2006 compared to one planned refuel outage and eight other outages that began during the three months ended June 30, 2005.

In late 2005, the generation levels of both Quad Cities’ units were reduced to pre-Extended Power Uprate (EPU) generation levels to address vibration-related equipment issues not directly related to the steam dryers. During the three months ended June 30, 2006, both Quad Cities’ units returned to EPU generation levels as compared to the three months ended June 30, 2005, when one of the Quad Cities’ units operated intermittently at pre-EPU generation levels and the other Quad Cities’ unit operated at pre-EPU generation levels due to performance issues with their steam dryers.

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


	Increase
	(Decrease)

Reduction in ARO	$	(149	)
2005 accrual for estimated future asbestos-related bodily injury claims		(43	)
Pension, payroll and benefit costs		33
Other		(3	)

Decrease in operating and maintenance expense	$	(162	)

This net $162 million decrease is primarily attributable to the following:


	•	The recognition of operating income of $149 million which represents the reduction in the ARO in excess of the existing ARO balance for the AmerGen units (see further discussion in Note 11 of the Combined Notes to Consolidated Financial Statements);

	•	A $43 million liability established in June 2005 for estimated future asbestos-related bodily injury claims (see Note 13 to the Combined Notes to Consolidated Financial Statements for further discussion); and

	•	A $33 million increase in various fringe benefits including increased stock-based compensation of $8 million and increased direct and allocated costs related to payroll, pension and other postretirement benefits expense.

Depreciation and Amortization. The increase in depreciation and amortization expense for the three months ended June 30, 2006 compared to the same period in 2005 was primarily due to the increase in depreciation expense as a result of recent capital additions.

Interest Expense. The increase in interest expense for the three months ended June 30, 2006 as compared to the same period in 2005 was attributable to higher interest rates on variable rate debt outstanding and higher interest expense on Generation’s one-time fee forpre-1983 spent nuclear fuel obligations to the Department of Energy.

Other, Net. The decrease in other income for the three months ended June 30, 2006 compared to the same period in 2005 was primarily due to gains realized in the second quarter of 2005 in the amount of $36 million related to the decommissioning trust fund investments for the AmerGen plants due to changes in Generation’s investment strategy. Realized gains associated with the decommissioning trust fund investments for the former PECO and ComEd units were $18 million in the second quarter of 2005, primarily as a result of changes in Generation’s investment strategy; however, as a result of the contractual construct, the gains on the investment associated with the former ComEd and PECO units are offset within Other, Net and have no impact on net income (see further discussion in Note 11 of the Combined Notes to Consolidated Financial Statements).

Effective Income Tax Rate. The effective income tax rate from continuing operations was 37.2% for the three months ended June 30, 2006 compared to 38.4% for the three months ended June 30, 2005. The decrease in the

effective income tax rate is due to a decrease in the pre-tax income of the qualified nuclear decommissioning trust funds for the three months ended June 30, 2006 as compared to the same period in 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Income and Comprehensive Income. Generation’s net income for the three months ended June 30, 2006 and 2005 reflects a gain on the sale of discontinued operations of $3 million and a loss of $1 million (both after tax), respectively. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

Results of Operations — Exelon Corporation

Six Months Ended June 30, 2006 Compared To Six Months Ended June 30, 2005


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
Exelon Corporation	2006			2005			Variance

Operating revenues	$	7,559		$	7,045		$	514
Operating expenses
Purchased power and fuel expense		2,534			2,347			(187	)
Operating and maintenance expense		1,906			1,877			(29	)
Depreciation and amortization		735			644			(91	)
Taxes other than income		364			349			(15	)

Total operating expenses		5,539			5,217			(322	)

Operating income		2,020			1,828			192
Other income and deductions		(415	)		(370	)		(45	)

Income from continuing operations before income taxes		1,605			1,458			147
Income taxes		564			435			(129	)

Income from continuing operations		1,041			1,023			18
Income from discontinued operations, net of income taxes		3			12			(9	)

Net income	$	1,044		$	1,035		$	9

Diluted earnings per share	$	1.55		$	1.53		$	0.02

Net Income. Exelon’s net income for the six months ended June 30, 2006 reflects higher realized prices on market sales and increased nuclear output at Generation; a decrease in Generation’s nuclear ARO resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily AmerGen nuclear plants; unrealizedmark-to-market gains; increased electric revenues at PECO associated with certain authorized rate increases; and increased kWh deliveries, excluding the effects of weather, reflecting load growth at ComEd and PECO. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories; reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset; increased depreciation and amortization expense, including CTC amortization at PECO; higher operating and maintenance expenses due to the impacts of inflation and increased stock-based compensation expense as a result of adoptingSFAS No. 123-R; and increased interest expense primarily associated with the debt issued in 2005 to fund Exelon’s pension contribution. Exelon’s net income for the six months ended June 30, 2005 reflected a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims; unrealizedmark-to-market gains; a gain resulting from the sale of Exelon’s investment in Sithe; favorable real estate tax settlements at PECO and Generation; and gains

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

Operating Revenues. Operating revenues increased primarily due to an increase in wholesale and retail electric sales and retail gas sales at Generation due to an increase in market prices; higher nuclear output; higher kWh deliveries at ComEd and PECO, excluding the effects of weather; and electric rate increases at PECO. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories; and amark-to-market loss associated with one wholesale contract at ComEd. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense. Purchased power and fuel expense increased primarily due to overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 17% of Generation’s total supply for the six months ended June 30, 2006 compared to 20% for the six months ended June 30, 2005. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to expenses related to stock-based compensation as a result of adoptingSFAS No. 123-R; the impairment of the intangible asset associated with the investments in synthetic fuel-producing facilities of $115 million; and the impacts of inflation, partially offset by the impact of the reduction in Generation’s nuclear asset retirement obligation,mark-to-market gains associated with Exelon’s investment in synthetic fuel-producing facilities, and a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO and additional plant placed in service.

Taxes Other Than Income. Taxes other than income increased primarily due to a reduction in 2005 of previously established real estate tax reserves at PECO and Generation and a net increase in utility revenue taxes at ComEd and PECO partially offset by favorable state franchise tax settlements at PECO in 2006.

Other Income and Deductions. The change in other income and deductions reflects increased interest expense associated with the debt issued in 2005 to fund Exelon’s voluntary pension contribution; higher interest rates on variable rate debt outstanding; higher interest expense on Generation’s one-time fee forpre-1983 spent nuclear fuel obligations; and an interest payment associated with a tax resolution at Generation related to Sithe.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 35.1% for the six months ended June 30, 2006 compared to 29.8% for the six months ended June 30, 2005. The increase in the income tax rate is primarily due to the phase-out of the income tax credits associated with Exelon’s investments in synthetic fuel-producing facilities. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

The income from discontinued operations decreased by $9 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005 partially offset by an adjustment to the gain on the sale of Sithe in the second quarter of 2006 as a result of the expiration of certain tax indemnifications.

100

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the six months ended June 30, 2006 compared to the same period in 2005 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Income from Continuing Operations by Business Segment


	Six Months
	Ended					Favorable
	June 30,					(Unfavorable)
	2006			2005		Variance

ComEd	$	181		$	179	$	2
PECO		186			239		(53	)
Generation		765			601		164
Other(a)		(91	)		4		(95	)

Total	$	1,041		$	1,023	$	18


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

Net Income by Business Segment


	Six Months
	Ended					Favorable
	June 30,					(Unfavorable)
	2006			2005		Variance

ComEd	$	181		$	179	$	2
PECO		186			239		(53	)
Generation		768			616		152
Other(a)		(91	)		1		(92	)

Total	$	1,044		$	1,035	$	9


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

101

Results of Operations — ComEd


	Six Months						Favorable
	Ended June 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	2,880		$	2,875		$	5
Operating expenses
Purchased power		1,628			1,679			51
Operating and maintenance		434			404			(30	)
Depreciation and amortization		205			198			(7	)
Taxes other than income		152			151			(1	)

Total operating expenses		2,419			2,432			13

Operating income		461			443			18

Other income and deductions
Interest expense		(153	)		(151	)		(2	)
Equity in losses of unconsolidated affiliates		(5	)		(8	)		3
Other, net		1			13			(12	)

Total other income and deductions		(157	)		(146	)		(11	)

Income before income taxes		304			297			7
Income taxes		123			118			(5	)

Net income	$	181		$	179		$	2

Net Income. ComEd’s net income for the six months ended June 30, 2006 compared to the same period in 2005 reflects slightly higher operating revenues and lower purchased power due to lower prices in ComEd’s PPA with Generation, partially offset by higher operating and maintenance expenses as more fully described below.

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


	Increase
	(Decrease)

Weather	$	(92	)
Volume		46
Customer choice		31
Rate changes and mix		13

Retail revenue		(2	)

Wholesale and miscellaneous revenues		15
Mark-to-market wholesale contract		(8	)

Increase in operating revenues	$	5

Weather. The amount of revenues attributable to weather conditions was lower due to unfavorable weather conditions for the six months ended June 30, 2006 compared to the same period in 2005. The demand for electricity is affected by weather conditions. In ComEd’s service territory, heating degree days were 10% lower and cooling degree days were 33% lower, during the six months ended June 30, 2006 compared to the same period in 2005.

Volume. Revenues were higher for the six months ended June 30, 2006 compared to the same period in 2005 due primarily to an increase in residential deliveries excluding the effects of weather due to increased customers and increased usage per customer.

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Customer choice. For the six months ended June 30, 2006 and 2005, 31% and 35%, respectively, of energy delivered to ComEd’s retail customers was provided by alternative electric suppliers or under the PPO.


	Six Months
	Ended June 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)		8,908			9,651
Percentage of total retail deliveries		21	%		22	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end		16,100			22,300
Percentage of total retail customers		(b	)		(b	)
Volume (GWhs)(a)		13,428			15,228
Percentage of total retail deliveries		31	%		35	%


(a)		One GWh is the equivalent of one million kilowatt hours (KWh).

(b)		Less than one percent.

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

Mark-to-market wholesale contract. Market-to-market wholesale contract reflects amark-to-market loss associated with one wholesale contract that had previously been recorded as a normal sale under FAS 133 in 2005. This contract expires in December 2007.

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


	Increase
	(Decrease)

Prices	$	(83	)
Weather		(52	)
Volume		28
Customer choice		27
SECA rates		24
PJM transmission		6
Other		(1	)

Decrease in purchased power expense	$	(51	)

103

prices in existence at that time. The PPA terminates at the end of 2006 and is expected to be replaced with the reverse-auction process approved by the ICC in January of this year. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the reverse-auction process.

Weather. The decrease in purchased power expense attributable to weather was due to unfavorable weather conditions in the ComEd service territory, which decreased the amount of electricity purchased.

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

Customer choice. The increase in purchased power expense from customer choice was primarily due to fewer ComEd non-residential customers electing to purchase energy from an alternative electric supplier due to the increase in market prices for energy.

SECA rates. Effective December 1, 2004, PJM became obligated to pay SECA collections to ComEd and ComEd became obligated to pay SECA charges. These charges were being collected subject to refund as they are being disputed. As a result of current events related to SECA disputes, during the first quarter of 2006, ComEd increased its reserve for amounts to be refunded. ComEd recorded SECA collections and payments on a net basis through purchased power expense. As ComEd was a net collector of SECA charges, the 2005 purchased power expense was lower than 2006 due to the expiration of SECA charges. SECA charges expired on March 31, 2006. See Note 5 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

PJM transmission. The increase in PJM transmission expense reflects increased peak and kWh consumption by ComEd-supplied customers due to load growth as well as an increase in ComEd-supplied customers driven by more customers choosing ComEd for supply due to alternative suppliers’ higher market prices partially offset by a decrease in ancillary charges.

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


	Increase
	(Decrease)

Fringe benefits(a)	$	15
Wages and salaries		7
PSEG merger integration costs		4
Corporate allocations		4
Severance-related expenses		3
Other		(3	)

Increase in operating and maintenance expense	$	30


(a)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $14 million primarily due to Exelon’s and ComEd’s adoption of SFAS No. 123-R on January 1, 2006 and increased pension and other postretirement benefits costs of $3 million.

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


	Increase
	(Decrease)

Depreciation expense associated with higher plant balances	$	5
Other amortization expense		2

Increase in depreciation and amortization expense	$	7

104

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


	Increase
	(Decrease)

Taxes on utility revenues(a)	$	(1	)
Other		2

Increase in taxes other than income	$	1


(a)		As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the decrease in expense was offset by a corresponding decrease in revenues.

Interest Expense. Interest expense remained constant for the six months ended June 30, 2006 compared to 2005.

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


	Increase
	(Decrease)

Gain (loss) on disposition of assets and investments, net	$	(6	)
Sale of receivable in 2005		(3	)
Interest income from intercompany money pool		(2	)
Other		(1	)

Decrease in other, net	$	(12	)

Income Taxes. The effective income tax rate was 40.5% for the six months ended June 30, 2006 compared to 39.7% for the six months ended June 30, 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

105

ComEd Electric Operating Statistics and Revenue Detail


	Six Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		12,921		13,346		(425	)		(3.2	)%
Small commercial & industrial		11,028		10,211		817			8.0	%
Large commercial & industrial		4,609		3,883		726			18.7	%
Public authorities & electric railroads		1,115		1,052		63			6.0	%

Total full service		29,673		28,492		1,181			4.1	%

PPO
Small commercial & industrial		2,322		2,458		(136	)		(5.5	)%
Large commercial & industrial		2,198		3,119		(921	)		(29.5	)%

		4,520		5,577		(1,057	)		(19.0	)%

Delivery only(b)
Small commercial & industrial		2,185		3,163		(978	)		(30.9	)%
Large commercial & industrial		6,723		6,488		235			3.6	%

		8,908		9,651		(743	)		(7.7	)%

Total PPO and delivery only		13,428		15,228		(1,800	)		(11.8	)%

Total retail deliveries		43,101		43,720		(619	)		(1.4	)%


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

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

106


	Six Months
	Ended June 30,
Electric Revenue	2006			2005		Variance			% Change

Full service(a)
Residential	$	1,096		$	1,124	$	(28	)		(2.5	)%
Small commercial & industrial		839			784		55			7.0	%
Large commercial & industrial		240			193		47			24.4	%
Public authorities & electric railroads		68			65		3			4.6	%

Total full service		2,243			2,166		77			3.6	%

PPO(b)
Small commercial & industrial		163			165		(2	)		(1.2	)%
Large commercial & industrial		132			171		(39	)		(22.8	)%

		295			336		(41	)		(12.2	)%

Delivery only(c)
Small commercial & industrial		33			58		(25	)		(43.1	)%
Large commercial & industrial		67			80		(13	)		(16.3	)%

		100			138		(38	)		(27.5	)%

Total PPO and delivery only		395			474		(79	)		(16.7	)%

Total electric retail revenues		2,638			2,640		(2	)		(0.1	)%
Wholesale and miscellaneous revenue(d)		250			235		15			6.4	%
Mark-to-market wholesale contract		(8	)		—		(8	)		n.m.

Total operating revenues	$	2,880		$	2,875	$	5			0.2	%


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

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

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

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

n.m. Not meaningful

107

Results of Operations — PECO


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	2,554		$	2,339		$	215
Operating expenses
Purchased power and fuel		1,389			1,200			(189	)
Operating and maintenance		289			253			(36	)
Depreciation and amortization		343			273			(70	)
Taxes other than income		117			115			(2	)

Total operating expenses		2,138			1,841			(297	)

Operating income		416			498			(82	)

Other income and deductions
Interest expense		(136	)		(142	)		6
Equity in losses of unconsolidated affiliates		(6	)		(8	)		2
Other, net		5			9			(4	)

Total other income and deductions		(137	)		(141	)		4

Income before income taxes		279			357			(78	)
Income taxes		93			118			25

Net income		186			239			(53	)
Preferred stock dividends		2			2			—

Net income on common stock	$	184		$	237		$	(53	)

Net Income. PECO’s net income for the six months ended June 30, 2006 compared to the same period in 2005 decreased primarily due to higher CTC amortization and higher operating and maintenance expense, partially offset by higher revenues, net of purchased power and fuel expense. Higher net revenues reflected certain authorized electric rate increases, including a scheduled CTC rate increase, partially offset by lower net electric and gas revenues as a result of unfavorable weather. The increases in CTC amortization expense and CTC rates are in accordance with PECO’s 1998 restructuring settlement with the PAPUC. The increase in CTC amortization expense exceeded the increase in CTC revenues.

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


							Total
							Increase
	Electric			Gas			(Decrease)

Rate increases	$	103		$	156		$	259
Customer choice		37			—			37
Volume		33			(13	)		20
Other rate changes and mix		15			—			15
Weather		(42	)		(82	)		(124	)

Retail revenue		146			61			207

Miscellaneous revenues		13			(5	)		8

Increase in operating revenues	$	159		$	56		$	215

108

Rate increases. The increase in electric revenues attributable to electric rate increases reflects scheduled CTC and energy rate increases in accordance with PECO’s 1998 restructuring settlement with the PAPUC and the elimination of the aggregate $200 million electric distribution rate reductions over the period January 1, 2002 through December 31, 2005 ($40 million in 2005) related to the PAPUC’s approval of the merger between PECO and ComEd. The increase in gas revenues was due to increases in rates through PAPUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2005, June 1, 2005 and December 1, 2005, partially offset by subsequent decreases in rates effective March 1, 2006 and June 1, 2006. The average purchased gas cost rate per million cubic feet in effect for the six months ended June 30, 2006 was 39% higher than the average rate for the same period in 2005.

Customer choice. For the six months ended June 30, 2006 and 2005, 2% and 7%, respectively, of energy delivered to PECO’s retail customers was provided by alternative electric suppliers.


	Six Months
	Ended
	June 30,
	2006			2005

Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end		38,300			71,200
Percentage of total retail customers		3	%		5	%
Volume (GWhs)(a)		406			1,222
Percentage of total retail deliveries		2	%		7	%


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

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

Weather. The demand for electricity and gas is affected by weather conditions. Revenues were negatively affected by unfavorable weather conditions in PECO’s service territory, where heating degree days were 19% lower during the six months ended June 30, 2006 compared to the same period in 2005. Cooling degree days were the same for both periods.

Miscellaneous revenues. Miscellaneous electric revenues increased primarily due to increased PJM transmission revenue, and miscellaneous gas revenues decreased primarily due to decreased off-system sales.

109

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


							Total
							Increase
	Electric			Gas			(Decrease)

Prices	$	73		$	156		$	229
Customer choice		37			—			37
PJM transmission		17			—			17
Weather		(18	)		(68	)		(86	)
Volume		11			(13	)		(2	)
Other		(2	)		(4	)		(6	)

Increase in purchased power and fuel expense	$	118		$	71		$	189

Prices. PECO’s purchased power expense increased $38 million corresponding to the increase in electric revenues which was attributable to the scheduled energy rate increase. In addition, PECO’s purchased power expense increased $35 million due to a change in the mix of average pricing related to its PPA with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Weather. The decrease in purchased power and fuel expense attributable to weather was primarily due to lower demand due to unfavorable weather conditions in the PECO service territory.

Other. The decrease in gas fuel expense was due to decreased off-system sales.

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


	Increase
	(Decrease)

Allowance for uncollectible accounts(a)	$	20
Fringe benefits(b)		15
PSEG merger integration costs		2
Environmental reserve(c)		(4	)
Contractors		(2	)
Other		5

Increase in operating and maintenance expense	$	36


(a)		Reflects the following factors, all of which increased expense in 2006 as compared to 2005: (i) higher accounts receivable balances in 2006 compared to 2005 resulting from increased revenues; (ii) changes in PAPUC-approved regulations which relaxed customer payment terms; and (iii) an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables.

110


(b)		Reflects increases in various fringe benefits including increased stock-based compensation expense of $7 million primarily due to Exelon’s and PECO’s adoption of SFAS No. 123-R on January 1, 2006 and increased pension and other postretirement benefits costs of $3 million.

(c)		Represents a settlement related to one Superfund site in the first quarter of 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information.


	Increase
	(Decrease)

CTC amortization	$	68
Other		2

Increase in depreciation and amortization expense	$	70

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

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


	Increase
	(Decrease)

Taxes on utility revenues(a)	$	10
Real estate tax adjustment in 2005(b)		6
State franchise tax adjustment in 2006(c)		(7	)
Sales and use tax adjustment in 2006(c)		(5	)
Other		(2	)

Increase in taxes other than income	$	2


(a)		As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in tax expense was offset by a corresponding increase in revenues. Includes a $3 million adjustment for the period 2001 through 2005.

(b)		Represents the reduction of a real estate tax accrual in the first quarter of 2005 following settlements related to prior year tax assessments. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information.

(c)		Represents the reduction of tax accruals in the second quarter of 2006 following settlements related to prior year tax assessments.

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

Other, net. The decrease was primarily due to gains on disposition of assets of $3 million in 2005.

Income Taxes. The effective income tax rate was 33.3% for the six months ended June 30, 2006 compared to approximately 33.1% for the six months ended June 30, 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

111

PECO Electric Operating Statistics and Revenue Detail

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


	Six Months
	Ended
	June 30,
Retail Deliveries — (in GWhs)	2006		2005		Variance			% Change

Full service(a)
Residential		5,917		5,955		(38	)		(0.6	)%
Small commercial & industrial		3,753		3,462		291			8.4	%
Large commercial & industrial		7,576		7,214		362			5.0	%
Public authorities & electric railroads		472		431		41			9.5	%

Total full service		17,718		17,062		656			3.8	%

Delivery only(b)
Residential		32		178		(146	)		(82.0	)%
Small commercial & industrial		345		712		(367	)		(51.5	)%
Large commercial & industrial		29		332		(303	)		(91.3	)%

Total delivery only		406		1,222		(816	)		(66.8	)%

Total retail deliveries		18,124		18,284		(160	)		(0.9	)%


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

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


	Six Months
	Ended
	June 30,
Electric Revenue	2006		2005		Variance			% Change

Full service(a)
Residential	$	795	$	744	$	51			6.9	%
Small commercial & industrial		446		386		60			15.5	%
Large commercial & industrial		614		546		68			12.5	%
Public authorities & electric railroads		43		40		3			7.5	%

Total full service		1,898		1,716		182			10.6	%

Delivery only(b)
Residential		2		13		(11	)		(84.6	)%
Small commercial & industrial		18		35		(17	)		(48.6	)%
Large commercial & industrial		1		9		(8	)		(88.9	)%

Total delivery only		21		57		(36	)		(63.2	)%

Total electric retail revenues		1,919		1,773		146			8.2	%

Miscellaneous revenues(c)		118		105		13			12.4	%

Total electric and other revenue	$	2,037	$	1,878	$	159			8.5	%


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

(b)		Delivery only revenue reflects revenue from customers receiving generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(c)		Miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

112

PECO Gas Sales Statistics and Revenue Detail

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


	Six Months
	Ended
	June 30,
Deliveries to Customers (in million cubic feet (mmcf))	2006		2005		Variance			% Change

Retail sales		31,213		37,532		(6,319	)		(16.8	)%
Transportation		13,019		13,564		(545	)		(4.0	)%

Total		44,232		51,096		(6,864	)		(13.4	)%


	Six Months
	Ended
	June 30,
Revenue	2006		2005		Variance			% Change

Retail sales	$	507	$	445	$	62			13.9	%
Transportation		8		9		(1	)		(11.1	)%
Resales and other		2		7		(5	)		(71.4	)%

Total gas revenue	$	517	$	461	$	56			12.1	%

Results of Operations — Generation


	Six Months
	Ended						Favorable
	June 30,						(Unfavorable)
	2006			2005			Variance

Operating revenues	$	4,434		$	4,125		$	309
Operating expenses
Purchased power and fuel		1,817			1,753			(64	)
Operating and maintenance		1,108			1,211			103
Depreciation and amortization		139			125			(14	)
Taxes other than income		84			74			(10	)

Total operating expenses		3,148			3,163			15

Operating income		1,286			962			324

Other income and deductions
Interest expense		(82	)		(58	)		(24	)
Equity in gains (losses) of unconsolidated affiliates		(5	)		4			(9	)
Other, net		20			69			(49	)

Total other income and deductions		(67	)		15			(82	)

Income from continuing operations before income taxes		1,219			977			242
Income taxes		454			376			(78	)

Income from continuing operations		765			601			164
Income from discontinued operations, net of income taxes		3			15			(12	)

Net income	$	768		$	616		$	152

Net Income. Generation’s net income for the six months ended June 30, 2006 compared to the same period in 2005 increased due to higher revenue, net of purchased power and fuel expense and lower operating and maintenance expense, partially offset by lower other income and deductions. The increase in Generation’s revenue, net of purchased power and fuel expense is related to realized revenues associated with forward sales entered into in

113

prior periods which were recognized at higher prices, combined with higher spot market prices and the impact of higher nuclear output. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. The decrease in operating and maintenance expense is primarily due to the recognition of operating income in the second quarter of 2006 associated with the reduction in the nuclear ARO. Generation’s net income for the six months ended June 30, 2006 and 2005 reflects income from discontinued operations of $3 million and $15 million (after tax), respectively.

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


	Six Months
	Ended
	June 30,
Revenue	2006		2005		Variance			% Change

Electric sales to affiliates	$	2,270	$	2,251	$	19			0.8	%
Wholesale and retail electric sales		1,689		1,443		246			17.0	%

Total energy sales revenue		3,959		3,694		265			7.2	%

Retail gas sales		340		284		56			19.7	%
Trading portfolio		5		9		(4	)		(44.4	)%
Other revenue(a)		130		138		(8	)		(5.8	)%

Total revenue	$	4,434	$	4,125	$	309			7.5	%


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


	Six Months
	Ended
	June 30,
Sales (in GWhs)	2006		2005		Variance			% Change

Electric sales to affiliates		57,870		57,035		835			1.5	%
Wholesale and retail electric sales		33,052		35,420		(2,368	)		(6.7	)%

Total sales		90,922		92,455		(1,533	)		(1.7	)%

Trading volumes of 14,754 GWhs and 11,411 GWhs for the six months ended June 30, 2006 and 2005, respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates increased $19 million for the six months ended June 30, 2006 compared to the same period in 2005. The increase in revenue from sales to affiliates was primarily due to a $34 million increase from higher electric sales volume, slightly offset by overall lower prices resulting in a $15 million decrease in revenues. In the ComEd territories, higher volumes, driven by customers not electing an alternative electric supplier, resulted in an $11 million increase in revenues. The increase in revenues associated with volumes was offset by lower peak prices in the purchased power agreement resulting in a $77 million decrease in revenues. Beginning in 2007, the PPA with ComEd will expire and be replaced with a reverse-auction bidding process approved by the ICC. In the PECO territories, the higher volumes related to customer choice resulted in an increase in revenues of $23 million. A change in the mix of average pricing resulted in an additional $62 million increase in revenues.

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


	Increase
	(Decrease)

Price	$	344
Volume		(98	)

Increase in wholesale and retail electric sales	$	246

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Wholesale and retail electric sales increased $246 million due to realized revenues associated with forward sales entered into in prior periods which were recognized at higher prices for the six months ended June 30, 2006 compared to the same period in 2005, partially offset by lower volumes of generation capacity sold to the market. Generation had less power to sell into the market as a result of higher demand for power sold to affiliates in 2006.

Retail gas sales. Retail gas sales increased $56 million primarily due to higher realized prices partially offset by lower gas volumes.

Other revenues. The decrease in other revenues for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to a decrease in volumes associated with fossil fuel sales.

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


	Six Months
	Ended
	June 30,
Supply Source (in GWhs)	2006		2005		Variance			% Change

Nuclear generation(a)		68,933		67,465		1,468			2.2	%
Purchases — non-trading portfolio		15,870		18,607		(2,737	)		(14.7	)%
Fossil and hydroelectric generation		6,119		6,383		(264	)		(4.1	)%

Total supply		90,922		92,455		(1,533	)		(1.7	)%


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

The changes in Generation’s purchased power and fuel expense for the six months ended June 30, 2006 compared to the same period in 2005 consisted of the following:


	Increase
	(Decrease)

Price	$	253
Volume		(194	)
Mark-to-market		5

Increase in purchased power and fuel expense	$	64

Price. Generation experienced overall higher market energy prices for purchased power in 2006 compared to the prior year, which was partially offset by Generation’s forward sales hedging program. In addition, realized prices for retail gas increased for the six months ended June 30, 2006, as compared to the same period in 2005.

Volume. The decreased volume for the six months ended June 30, 2006 as compared to the same period in 2005 was primarily due to lower purchased power and retail gas volumes, slightly offset by higher generation needed to meet ComEd and PECO’s load requirements.

Mark-to-market. Mark-to-market gains on hedging activities were $36 million for the six months ended June 30, 2006 compared to gains of $41 million for the same period in 2005.

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


	Six Months
	Ended
	June 30,
($/MWh)	2006		2005		% Change

Average electric revenue
Electric sales to affiliates	$	39.23	$	39.47		(0.6	)%
Wholesale and retail electric sales		51.10		40.74		25.4	%
Total — excluding the trading portfolio		43.54		39.95		9.0	%
Average electric supply cost(a) — excluding the trading portfolio		16.23		16.04		1.2	%
Average margin — excluding the trading portfolio		27.31		23.91		14.2	%


(a)		Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales and other sales.

Nuclear fleet operating data for the six months ended June 30, 2006 and 2005 were as follows:


	Six Months
	Ended
	June 30,
	2006			2005

Nuclear fleet capacity factor(a)		93.3	%		92.7	%
Nuclear fleet production cost per MWh(a)	$	14.19		$	13.24


(a)		Excludes Salem, which is operated by PSEG Nuclear, LLC.

The nuclear fleet capacity factor increased due to fewer planned refueling outage days and non-refueling outage days during the six months ended June 30, 2006 compared to the same period in 2005. For the six months ended June 30, 2006 and 2005, refueling outage days totaled 114 and 128, respectively. Total non-refueling outage days for the six months ended June 30, 2006 and 2005 were 49 and 55, respectively. Higher costs for nuclear fuel amortization and inspections and maintenance during planned refueling outages and non-refueling outages, a Nuclear Regulatory Commission (NRC) fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated and resulted in a higher production cost per MWh produced for the six months ended June 30, 2006 as compared to the same period in 2005. There were five planned refueling outages and ten non-refueling outages that began during the six months ended June 30, 2006 compared to five planned refueling outages and fifteen other outages that began during the six months ended June 30, 2005.

In late 2005, the generation levels of both Quad Cities’ units were reduced to pre-Extended Power Uprate (EPU) generation levels to address vibration-related equipment issues not directly related to the steam dryers. During the six months ended June 30, 2006, both Quad Cities units returned to EPU generation levels as compared to the six months ended June 30, 2005, when one of the Quad Cities’ units operated intermittently at EPU generation levels and the other Quad Cities’ unit operated at pre-EPU generation levels due to performance issues with their steam dryers.

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


	Increase
	(Decrease)

Reduction in ARO	$	(149	)
2005 accrual for estimated future asbestos-related bodily injury claims		(43	)
Pension, payroll and benefit costs		76
Other		13

Decrease in operating and maintenance expense	$	(103	)

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This net $103 million decrease is primarily attributable to the following:


	•	The recognition of operating income of $149 million which represents the reduction in the ARO in excess of the existing ARO balance for the AmerGen units (see further discussion in Note 11 of the Combined Notes to Consolidated Financial Statements);

	•	A $43 million liability established in June 2005 for estimated future asbestos-related bodily injury claims (see Note 13 to the Combined Notes to Consolidated Financial Statements for further discussion); and

	•	A $76 million increase in various fringe benefits including increased stock-based compensation of $22 million primarily as a result of Exelon’s adoption of SFAS No. 123-R as of January 1, 2006 and increased direct and allocated costs related to payroll, pension and other postretirement benefits expense.

Depreciation and Amortization. The increase in depreciation and amortization expense for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to the increase in depreciation expense as a result of recent capital additions.

Taxes Other Than Income. The increase in taxes other than income for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to a reduction in 2005 of a previously established real estate reserve recorded in 2005 associated with the settlement over the Three Mile Island Nuclear Station real estate assessment.

Interest Expense. The increase in interest expense for the six months ended June 30, 2006 as compared to the same period in 2005 was attributable to higher interest rates on variable rate debt outstanding, higher interest expense on Generation’s one-time fee forpre-1983 spent nuclear fuel obligations to the Department of Energy and an interest payment made to the Internal Revenue Service in settlement of a tax matter.

Other, Net. The decrease in other income for the six months ended June 30, 2006 compared to the same period in 2005 was primarily due to gains realized in the second quarter of 2005 in the amount of $36 million related to the decommissioning trust fund investments for the AmerGen plants due to changes in Generation’s investment strategy and merger-related expenses recorded during the six months ended June 30, 2006. Realized gains associated with the decommissioning trust fund investments for the former PECO and ComEd units were $18 million in the second quarter of 2005, primarily as a result of changes in Generation’s investment strategy; however, as a result of the contractual construct, the gains on the investment associated with the former ComEd and PECO units are offset within Other, Net and have no impact on net income (see further discussion in Note 11 of the Combined Notes to Consolidated Financial Statements).

Effective Income Tax Rate. The effective income tax rate from continuing operations was 37.2% for the six months ended June 30, 2006 compared to 38.5% for the six months ended June 30, 2005. The decrease in the effective income tax rate is due to a decrease in the pre-tax income of the qualified nuclear decommissioning trust funds for the six months ended June 30, 2006 as compared to the same period in 2005. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Income and Comprehensive Income. Generation’s net income for the six months ended June 30, 2006 and 2005 reflects a gain on the sale of discontinued operations of $3 million and $15 million (both after tax), respectively. See Notes 2 and 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the Presentation of Sithe as discontinued operations.

Liquidity and Capital Resources

Capital resources are primarily provided by internally generated cash flows from operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing on reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that Exelon no longer has access to the capital markets at reasonable terms, Exelon, PECO and Generation have access to

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revolving credit facilities with aggregate bank commitments of $1.5 billion that they currently utilize to support their commercial paper programs. In addition, ComEd and Generation have access to separate revolving credit facilities with aggregate bank commitments of $1 billion and $950 million, respectively. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion. Exelon expects cash flows to be sufficient to meet operating, financing and capital expenditure requirements. See “Liquidity and Capital Resources” within Exelon’s 2005 Annual Report onForm 10-K for further information.

Exelon’s, ComEd’s and PECO’s working capital, defined as current assets less current liabilities, are in net deficit positions primarily due to continued capital expenditures to improve and expand their service systems, current portions of debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust as well as maturing long-term debt at ComEd. ComEd intends to refinance the maturing long-term debt during 2006. As more fully described below, ComEd did not pay a dividend during the six months ended June 30, 2006.

Cash Flows from Operating Activities

ComEd’s and PECO’s cash flows from operating activities primarily result from sales of electricity and, in the case of PECO, gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter of each fiscal year. ComEd’s and PECO’s future cash flows will be affected by the economy, weather, customer choice, existing and future regulatory proceedings relating to their revenues and their ability to achieve operating cost reductions. See Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including ComEd and PECO. Generation’s future cash flows from operating activities will be affected by demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs.

Cash flows from operations have been a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder the ability of PECO to fund its business requirements. Beginning in 2007, ComEd will purchase energy in the wholesale energy markets in order to meet the retail energy needs of ComEd’s customers because ComEd does not own any generation. If the price at which ComEd is allowed to sell energy beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be potential material adverse consequences to ComEd and, possibly, Exelon. ComEd has proposed a “cap and deferral” program to mitigate the impact on its residential customers of transitioning to the post rate freeze period. If approved as proposed and implemented, ComEd’s cash flows from operations would be reduced in the first years of the program, but would increase as any deferred amounts are collected with an appropriate return on any deferred balances. See Note 5 of the Combined Notes to Consolidated Financial Statements for further discussion of ComEd’s procurement case.

Additionally, Exelon, through ComEd, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As discussed in Note 10 of the Combined Notes to Consolidated Financial Statements, this tax obligation is significant, and an adverse determination could require a significant payment.

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The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the six months ended June 30, 2006 and 2005:


	Six Months
	Ended June 30,
	2006			2005			Variance

Net income	$	1,044		$	1,035		$	9
Add (subtract):
Non-cash operating activities(a)		1,091			1,547			(456	)
Income taxes		300			24			276
Changes in working capital and other noncurrent assets and liabilities(b)		(346	)		(393	)		47
Pension and non-pension postretirement benefits		99			(1,927	)		2,026

Net cash flows provided by (used in) operations	$	2,188		$	286		$	1,902


(a)		Represents depreciation, amortization and accretion, deferred income taxes, pension and non-pension postretirement benefit costs, equity in losses of unconsolidated affiliates, impairment charges and other non-cash charges.

(b)		Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

The increase of cash flows from operations during the six months ended June 30, 2006 compared to the same period in 2005 was primarily the result of $2 billion of discretionary contributions to Exelon’s pension plans, including contributions of $803 million, $109 million and $844 million by ComEd, PECO and Generation, respectively, during the first quarter of 2005, which was initially funded through a term loan agreement, as further described in the “Cash Flows from Financing Activities” section below. The Generation contribution was primarily funded by capital contributions from Exelon and included $2 million from internally generated funds.

Cash flows provided by (used in) operations for the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months
	Ended June 30,
	2006		2005

Exelon	$	2,188	$	286
ComEd		575		(128	)
PECO		562		301
Generation		1,072		380

Excluding the March 2005 discretionary pension contributions discussed above, changes in Exelon’s, ComEd’s, PECO’s and Generation’s cash flows from operations were generally consistent with changes in its results of operations, as adjusted by changes in working capital in the normal course of business.

In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 2006 and 2005 were as follows:

Exelon


	•	During the six months ended June 30, 2006 and June 30, 2005, Exelon recorded impairment charges of $117 million and $0, respectively. As Exelon does not anticipate earning sufficient future tax credits to support the value of the intangible asset associated with Exelon’s investment in synthetic fuel-producing facilities, Exelon recorded an impairment charge of $115 million ($69 million after tax) during the second quarter of 2006. See Note 10 of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s investment in synthetic fuel-producing facilities.

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ComEd


	•	At June 30, 2006 and December 31, 2005, ComEd had accrued payments to Generation under the PPA of $247 million and $242 million, respectively. At June 30, 2005 and December 31, 2004, ComEd had accrued payments to Generation under the PPA of $331 million and $189 million, respectively.

Generation


	•	During the three months ended June 30, 2006 and 2005, Generation had net collections and net disbursements of counterparty collateral of $183 million and $13 million, respectively. The increase in cash flows was primarily due to changes in collateral requirements resulting from increased activity within exchange-based markets for energy and fossil fuel.

	•	In January 2005, Exelon received a $102 million Federal income tax refund for capital losses generated in 2003 related to Generation’s previously owned investment in Sithe, which were carried back to prior periods. In the first quarter of 2006, Exelon remitted a $98 million payment to the IRS in connection with the settlement of the IRS’s challenge of the timing of the above-described deduction. This payment included $6 million of interest which was recognized as interest expense in the first quarter of 2006. Exelon expects to receive, in either the fourth quarter of 2006 or the first quarter of 2007, approximately $92 million related to this same deduction in connection with the filing of its 2005 tax return.

Cash Flows from Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months
	Ended June 30,
	2006			2005

Exelon	$	(1,360	)	$	(1,143	)
ComEd		(461	)		(104	)
PECO		(157	)		(58	)
Generation		(666	)		(592	)

Capital expenditures by registrant and business segment for the six months ended June 30, 2006 and projected amounts for the twelve months ended 2006 are as follows:


	Six Months Ended		Projected
	June 30, 2006		2006

ComEd	$	465	$	925
PECO		164		333
Generation		512		1,115
Other(a)		15		68

Total Exelon capital expenditures	$	1,156	$	2,441


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

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

ComEd and PECO. Approximately 50% of the projected 2006 capital expenditures at ComEd and PECO are for continuing projects to maintain and improve the reliability of their transmission and distribution systems. The remaining amount is for capital additions to support new business and customer growth. Exelon is continuing to evaluate its total capital spending requirements. Exelon anticipates that ComEd’s and PECO’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities.

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Generation. Generation’s capital expenditures for 2006 reflect additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.

Other significant investing activities of the Registrants for the six months ended June 30, 2006 and 2005 were as follows:

Exelon


	•	Exelon contributed $53 million and $56 million to its investments in synthetic fuel-producing facilities during the six months ended June 30, 2006 and 2005, respectively.

ComEd


	•	As a result of its prior contributions to the Exelon intercompany money pool, $287 million was returned to ComEd during the six months ended June 30, 2005.

PECO


	•	As a result of its prior contributions to the Exelon intercompany money pool, $8 million and $34 million were returned to PECO during the six months ended June 30, 2006 and 2005, respectively.

	•	During the six months ended June 30, 2005, there was a net decrease in restricted cash that provided $28 million of cash.

Generation


	•	On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation acquired Reservoir Capital Group’s 50% interest in Sithe for cash payments of $97 million and sold 100% of Sithe to Dynegy, for net cash proceeds of $103 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of the sale of Sithe.

	•	During the six months ended June 30, 2005, Generation received approximately $33 million from Generation’s nuclear decommissioning trust funds for reimbursement of expenditures previously incurred for nuclear plant decommissioning activities related to the retired units.

Acquisition of the Remaining Interest of Southeast Chicago Energy Project, LLC (SCEP). Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of SCEP, a 350-megawatt natural gas-fired, peaking electric power plant located in Chicago, Illinois, which began operation in 2002. In 2002, Generation and Peoples Calumet owned 70% and 30%, respectively, of SCEP. Generation reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a20-year period.

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Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months Ended
	June 30,
	2006			2005

Exelon	$	(686	)	$	903
ComEd		(118	)		339
PECO		(417	)		(268	)
Generation		(416	)		241

Debt. On March 6, 2006, ComEd issued $325 million aggregate principal amount of its First Mortgage 5.90% Bonds, Series 103, due March 15, 2036. The proceeds of the bonds were used to supplement working capital previously used to refinance amounts that ComEd used to repay $54 million First Mortgage 9.875% Bonds, Series 75, due June 15, 2020, which ComEd redeemed in 2005; $163 million First Mortgage 7.00% Bonds, Series 93, which matured July 1, 2005; and $107 million 6.4% Notes which matured October 15, 2005.

On March 7, 2005, Exelon entered into a $2 billion term loan agreement. The loan proceeds were used to fund discretionary contributions of $2 billion to Exelon’s pension plans, including contributions of $803 million, $109 million and $842 million by ComEd, PECO and Generation, respectively. To facilitate the contributions by ComEd, PECO and Generation, Exelon contributed the corresponding amounts to the capital of each company. See Note 10 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for further information.

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen their respective balance sheets.

Dividends. Cash dividend payments and distributions during the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months Ended
	June 30,
	2006		2005

Exelon	$	535	$	535
ComEd		—		245
PECO		253		233
Generation		322		319

Exelon paid dividends of $267 million and $268 million on March 10, 2006 and June 12, 2006, respectively, to shareholders of record at the close of business on February 15, 2006 and May 15, 2006, respectively. In preparation for the potential closing of the Merger with PSEG, the Exelon Board of Directors has declared alternative dividends, contingent upon the date of the closing of the Merger. A pro rata dividend of $0.00435 per share per day, accruing from May 15, 2006, is payable to shareholders of record at the close of business on the day before the Merger if and only if the Merger is closed on or before August 15, 2006. A dividend of $0.40 per share on Exelon’s common stock is payable on September 11, 2006 to shareholders of record at the close of business on August 15, 2006 if and only if the Merger is closed after August 15, 2006. A pro rata dividend of $0.00435 per share per day, accruing from August 15, 2006, is payable to shareholders of record at the close of business on the day before the Merger if and only if the Merger is closed after August 15, 2006 and on or before November 15, 2006. A dividend of $0.40 per share on Exelon’s common stock is payable on December 11, 2006 to shareholders of record at the close of business on November 15, 2006 if and only if the Merger is closed after November 15, 2006. The pro rata dividend, if it becomes payable, will be paid within 30 days after the closing of the Merger. The pro rata dividend is equivalent to $0.40 per share for the full quarter. See “Dividends” section of ITEM 5 of Exelon’s 2005 Annual Report onForm 10-K for a further discussion of Exelon’s dividend policy.

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During the six months ended June 30, 2006, ComEd did not pay a quarterly dividend. This decision by the ComEd Board of Directors not to declare a dividend was the result of several factors including ComEd’s need for a rate increase to cover existing costs and anticipated levels of future capital expenditures as well as the continued uncertainty related to ComEd’s regulatory filings as discussed in Note 5 of the Combined Notes to Consolidated Financial Statements. ComEd’s Board of Directors will continue to assess ComEd’s ability to pay a dividend on quarterly basis.

The Merger agreement with PSEG provides that Exelon will increase its quarterly dividend so that the first dividend paid after the Merger is equal, on an exchange ratio adjusted basis, to the dividend PSEG shareholders received in the quarter immediately prior to the Merger, up to a maximum of $0.47 per share of Exelon common stock. See Note 3 of the Combined Notes to Consolidated Financial Statements for information on the proposed Merger with PSEG.

In 2003, Congress passed and President Bush signed into law the Jobs and Growth Tax Reconciliation Act, legislation which lowered the tax rate on capital gains and corporate dividends to 15% for most investors and to 5% for lower-income investors. Prior to enactment of this law, the maximum tax rate on dividend income was 38.6%. These provisions, which were originally scheduled to expire at the end of 2008, were extended to 2010 as part of the Tax Relief Reconciliation Act of 2005 passed in May 2006.

Intercompany Money Pool. During the six months ended June 30, 2006, ComEd repaid $140 million that it had borrowed from the Exelon Intercompany money pool. Generation’s net borrowings from the Exelon intercompany money pool decreased $92 million and $283 million during the six months ended June 30, 2006 and June 30, 2005, respectively.

Commercial Paper. During the six months ended June 30, 2006, ComEd repaid $120 million of commercial paper.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months Ended June 30,
	2006			2005

Exelon	$	(422	)	$	(397	)
ComEd		(174	)		(190	)
PECO		(248	)		(207	)

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during the six months ended June 30, 2006 and 2005 by registrant were as follows:


	Six Months Ended June 30,
	2006		2005

ComEd	$	—	$	834
PECO		71		180
Generation		—		843

Other. Other significant financing activities for Exelon for the six months ended June 30, 2006 and 2005 were as follows:


	•	Exelon purchased treasury shares totaling $53 million and $8 million during the six months ended June 30, 2006 and 2005, respectively.

	•	Exelon received proceeds from employee stock plans of $107 million and $156 million during the six months ended June 30, 2006 and 2005, respectively.

	•	There was $29 million and $0 of excess tax benefits included as a cash inflow in other financing activities during the six months ended June 30, 2006 and 2005, respectively.

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Credit Matters

Exelon Credit Facilities. Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Registrants. The Registrants may use credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

At June 30, 2006, the Registrants had the following bank commitments and available capacity under the various credit agreements to which they are a party and the indicated amounts of outstanding commercial paper:


	Aggregate Bank		Available		Outstanding
Borrower	Commitment(a)		Capacity(b)		Commercial Paper

Exelon(c)	$	200	$	200	$	10
ComEd		1,000		957		339
PECO(c)		500		500		227
Generation(c)		1,750		1,658		309


(a)		Represents the total bank commitments to the borrower under credit agreements to which the borrower is a party.

(b)		Available capacity represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(c)		Exelon, PECO and Generation are parties to two credit agreements with aggregate bank commitments of $1.5 billion. The credit agreements contain separate sublimits for Exelon, PECO and Generation, which are reflected in the table, which sublimits may be changed upon written notification to the bank group. Generation is also party to bilateral credit agreements with various banks with aggregate bank commitments of $950 million, which are reflected in the table above.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. In the cases of Exelon, PECO and Generation, the maximum LIBOR adder is 170 basis points; and in the case of ComEd, it is 200 basis points.

The average interest rates on commercial paper for the six months ended June 30, 2006 for Exelon, ComEd, PECO and Generation were approximately 4.87%, 4.86%, 4.79% and 4.83%, respectively.

The credit agreements require the Registrants to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the six-month period ended June 30, 2006:


	Exelon	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, 2006, the Registrants were in compliance with the foregoing thresholds.

The ComEd credit agreement imposes a restriction on future mortgage bond issuances by ComEd. It requires ComEd to maintain at least $1.75 billion of issuance availability (ignoring any interest coverage test) in the form of “property additions” or “bondable bond retirements” (previously issued, but now retired, bonds), most of which are required to be maintained in the form of “bondable bond retirements.” In general, a dollar of bonds can be issued under ComEd’s Mortgage on the basis of $1.50 of property additions, subject to an interest coverage test, or $1 of bondable bond retirements, which may or may not be subject to an interest coverage test. As of June 30, 2006, ComEd was in compliance with this requirement.

Intercompany Money Pool. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the six

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months ended June 30, 2006 are described in the following table in addition to the net contribution or borrowing as of June 30, 2006:


					June 30,
					2006
	Maximum		Maximum		Contributed
	Contributed		Borrowed		(Borrowed)

ComEd(a)	$	—	$	140	$	—
PECO		21		83		—
Generation		83		206		—
BSC		105		134		—
UII, LLC		4		—		—
Exelon		248		—		—


(a)		As of January 10, 2006, ComEd suspended participation in the intercompany money pool. During the first quarter of 2006, ComEd repaid $140 million that it had borrowed from the intercompany money pool.

Security Ratings. The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets.

On July 26, 2006, Moody’s Investors Service downgraded the long-term and short-term debt ratings of ComEd. The rating action concludes Moody’s review for possible downgrade that commenced on December 15, 2005. Moody’s attributes the downgrade to a difficult political and regulatory environment in Illinois, uncertainty about the outcome of the power supply auction and the expectation of a material regulatory deferral. ComEd’s rating outlook is negative.

On July 31, 2006, Fitch Ratings downgraded the long-term ratings of ComEd. ComEd’s short-term rating is affirmed at F2. The rating outlook remains negative. The rating action reflects Fitch’s view of the unfavorable rate order issued by the ICC and Fitch’s uncertainty in Illinois with respect to the power procurement process scheduled for implementation in January 2007.

The new ratings are shown below.


		Fitch
	Moody’s	Ratings

Senior Secured Debt	Baa2	BBB+
Commercial Paper	P-3

The debt ratings and rating outlook for Exelon, Generation and PECO are unchanged. None of the Registrants’ borrowings are subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under the Registrants’ credit agreements.

Investments in Synthetic Fuel-Producing Facilities

Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. Section 45K (formerly Section 29) of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45K contains a provision under which credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds.

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to idle synthetic fuel production was primarily driven by the level and volatility of oil prices in the second quarter of 2006. In addition, the proposed federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. Synthetic fuel production may resume in the future, but is dependent upon various factors including a reduction in oil prices or the enactment of future federal tax legislation. If oil prices continue to increase from current levels, Exelon may no longer earn tax credits related to the investments for the remainder of 2006 and 2007. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion.

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Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. The Registrants’ contractual obligations and commercial commitments as of June 30, 2006 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2005 Annual Report onForm 10-K except for the following:

Exelon


	•	Letters of credit increased $61 million and guarantees decreased $85 million, respectively, primarily as a result of Generation’s energy trading activities.

ComEd


	•	Letters of credit increased $16 million.

	•	ComEd issued $325 million First Mortgage 5.90% Bonds, Series 103, due March 15, 2036.

Generation


	•	Letters of credit increased $45 million and guarantees decreased $62 million, respectively, primarily as a result of Generation’s energy trading activities.

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

Also, as PSEG maintains a 22.84% ownership interest in the Keystone generating station, Exelon’s total commitment to the project would exceed $300 million upon the completion of the pending merger with PSEG.

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COMMONWEALTH EDISON COMPANY

General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services in northern Illinois, including the City of Chicago.

Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of thisForm 10-Q.

Results of Operations

A discussion of items pertinent to ComEd’s results of operations for the three months ended June 30, 2006 compared to three months ended June 30, 2005 and six months ended June 30, 2006 compared to six months ended June 30, 2005 is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of thisForm 10-Q.

Liquidity and Capital Resources

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper. ComEd’s access to external financing at reasonable terms may be significantly affected by developments in or related to the proceedings concerning its post-2006 rates and recovery of energy costs and will also be affected by its credit ratings and general business conditions, as well as that of the utility industry in general. See Note 5 of the Combined Notes to Consolidated Financial Statements for information regarding ComEd’s post-2006 rates and recovery of energy costs, including pending legislation to extend the current rate freeze. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans.

Cash Flows from Operating Activities

A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Credit Matters

A discussion of items pertinent to ComEd’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to ComEd’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

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PECO ENERGY COMPANY

General

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

Executive Overview

A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of thisForm 10-Q.

Results of Operations

A discussion of items pertinent to PECO’s results of operations for the three months ended June 30, 2006 compared to three months ended June 30, 2005 and six months ended June 30, 2006 compared to six months ended June 30, 2005 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of thisForm 10-Q.

Liquidity and Capital Resources

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to revolving credit facilities that PECO currently utilizes to support its commercial paper program. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans.

Cash Flows from Operating Activities

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

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Credit Matters

A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

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EXELON GENERATION COMPANY

General

Generation operates in a single business segment and its operations consist principally of the electric generating facilities and wholesale energy marketing operations of Generation, the competitive retail sales business of Exelon Energy Company and certain other generation projects.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of thisForm 10-Q.

Results of Operations

A discussion of items pertinent to Generation’s results of operations for the three months ended June 30, 2006 compared to three months ended June 30, 2005 and six months ended June 30, 2006 compared to six months ended June 30, 2005 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of thisForm 10-Q.

Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to revolving credit facilities that Generation currently utilizes to support its commercial paper program and to issue letters of credit. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

Cash Flows from Operating Activities

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

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Credit Matters

A discussion of items pertinent to Generation’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to Generation’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of thisForm 10-Q.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the derivative and risk management activities.

Commodity Price Risk (Exelon, ComEd and Generation)

To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather, governmental regulatory and environmental policies, and other factors. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electric capacity, energy and fossil fuels including oil, gas, coal and emission allowances. Exelon’s primary source of commodity price risk is at Generation; however, ComEd also has some commodity price risk associated with certain wholesale contracts.

ComEd

ComEd has one wholesale contract accounted for as a derivative under SFAS No. 133. This contract, which previously qualified for the normal purchase and normal sales exception to SFAS No. 133, has been recorded at fair value beginning in the first quarter of 2006 since the exception is no longer applicable. As of June 30, 2006, the fair value of this contract of $8 million was recorded on ComEd’s Consolidated Balance Sheet, of which $5 million is classified as a current liability and $3 million is classified as a long-term liability.

Generation

Generation’s energy contracts are accounted for under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). Non-trading contracts qualify for the normal purchases and normal sales exception to SFAS No. 133, which is discussed in Critical Accounting Policies and Estimates within Exelon’s 2005 Annual Report onForm 10-K. Energy contracts that do not qualify for the normal purchases and normal sales exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in other comprehensive income (OCI), and gains and losses are recognized in earnings when the underlying transaction occurs or are designated as fair-value hedges, in which case those changes are recognized in current earnings offset by changes in the fair value of the hedged item in current earnings. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 or are not designated as such are recognized in current earnings.

Normal Operations and Hedging Activities. Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being cash-flow hedged is three years. Generation has an estimated 90% hedge ratio in 2006 for its energy marketing portfolio. This hedge ratio represents the percentage of its forecasted aggregate annual economic generation supply that is committed to firm sales, including sales to ComEd’s and PECO’s retail load. ComEd’s and PECO’s retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. During peak periods, Generation’s amount hedged declines to meet its energy and capacity

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commitments to ComEd and PECO. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any efforts to mitigate market price exposure, the estimated market price exposure for Generation’s unhedged non-trading portfolio associated with a ten percent reduction in the annual averagearound-the-clock market price of electricity is approximately a $30 million decrease in net income for the remainder of 2006. 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.

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load obligations through 2006. At times, ComEd’s load obligations are greater than the capacity of Generation’s owned generating units in the ComEd region. As such, Generation procures power through purchase power and lease agreements and has contracted for access to additional generation through bilateral long-term PPAs. Following the expiration of the Illinois transition period and the end of the PPA between Generation and ComEd in 2006, all of Generation’s supply in the ComEd region will be available for sale into the wholesale markets and exposed to changes in market prices.

Proprietary Trading Activities. Generation began to use financial contracts for proprietary trading purposes in 2001. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on amark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than one percent of Generation’s owned and contracted supply of electricity. Generation expects this level of proprietary trading activity to continue in the future. Trading portfolio activity for the six months ended June 30, 2006 resulted in a realized gain of $5 million (before income taxes). Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating itsValue-at-Risk (VaR). The daily VaR on proprietary trading activity averaged $90,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the six months ended June 30, 2006 of $2,617 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss andvalue-at-risk limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities.

Trading and Non-Trading Marketing Activities. The following detailed presentation of the trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

The following table provides detail on changes in Generation’smark-to-market net asset or liability balance sheet position from January 1, 2006 to June 30, 2006. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates themark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets.


	Total

Totalmark-to-market energy contract net liabilities at January 1, 2006	$	(540	)
Total change in fair value during 2006 of contracts recorded in earnings		(23	)
Reclassification to realized at settlement of contracts recorded in earnings		60
Reclassification to realized at settlement from OCI		112
Effective portion of changes in fair value — recorded in OCI		269
Purchase/sale/disposal of existing contracts or portfolios subject tomark-to-market		—

Totalmark-to-market energy contract net liabilities at June 30, 2006	$	(122	)

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The following table details the balance sheet classification of Generation’smark-to-market energy contract net assets (liabilities) recorded as of June 30, 2006 and December 31, 2005:


	June 30,			December 31,
	2006			2005

Current assets	$	699		$	916
Noncurrent assets		473			286

Totalmark-to-market energy contract assets		1,172			1,202

Current liabilities		(874	)		(1,282	)
Noncurrent liabilities		(420	)		(460	)

Totalmark-to-market energy contract liabilities		(1,294	)		(1,742	)

Totalmark-to-market energy contract net liabilities	$	(122	)	$	(540	)

The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers orover-the-counter, on-line exchanges. Prices reflect the average of the bid-ask mid-point prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, region and product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of June 30, 2006 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts Exelon holds and sells. These estimates consider various factors including closing exchange andover-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

The following table, which presents maturity and source of fair value ofmark-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 totalmark-to-market asset or liability. Second, this table provides the maturity, by year, of Generation’s net assets/liabilities, giving an indication of when thesemark-to-market amounts will settle and either generate or require cash.


	Maturities Within
														2011 and		Total Fair
(In millions)	2006			2007			2008			2009		2010		Beyond		Value

Normal Operations, qualifying cash-flow hedge contracts(a):
Actively quoted prices	$	—		$	—		$	—		$	—	$	—	$	—	$	—
Prices provided by other external sources		(140	)		(22	)		22			—		—		—		(140	)

Total	$	(140	)	$	(22	)	$	22		$	—	$	—	$	—	$	(140	)

Normal Operations, other derivative contracts (b):
Actively quoted prices	$	(56	)	$	(12	)	$	12		$	—	$	—	$	—	$	(56	)
Prices provided by other external sources		53			29			(7	)		—		—		—		75
Prices based on model or other valuation methods		(17	)		15			1			—		—		—		(1	)

Total	$	(20	)	$	32		$	6		$	—	$	—	$	—	$	18


(a)		Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in OCI.

(b)		Mark-to-market gains and losses on other non-trading and trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

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The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of June 30, 2006. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s hedges. The table also includes a roll-forward of accumulated OCI related to cash-flow hedges from January 1, 2006 to June 30, 2006, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.


	Total Cash-Flow Hedge OCI Activity,
	Net of Income Tax
	Power Team Normal			Interest-Rate			Total
	Operations and			and Other			Cash-Flow
(In millions)	Hedging Activities			Hedges			Hedges

Accumulated OCI derivative loss at January 1, 2006	$	(314	)	$	(4	)	$	(318	)
Changes in fair value		163			2			165
Reclassifications from OCI to net income		67			—			67

Accumulated OCI derivative loss at June 30, 2006	$	(84	)	$	(2	)	$	(86	)

Credit Risk (Exelon and Generation)

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 and letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure, net of collateral, as of June 30, 2006. They further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include sales to Generation’s affiliates or exposure through Independent System Operators (ISOs) which are discussed below.


	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of June 30, 2006(a)	Collateral		Collateral		Exposure		of Net Exposure		of Net Exposure

Investment grade	$	700	$	139	$	561		1	$	93
Non-investment grade		12		2		10		—		—
No external ratings
Internally rated — investment grade		45		17		28		—		—
Internally rated — non-investment grade		5		4		1		—		—

Total	$	762	$	162	$	600		1	$	93


(a)		This table does not include accounts receivable exposure.

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	Maturity of Credit Risk Exposure
					Exposure		Total Exposure
	Less than				Greater than		Before Credit
Rating as of June 30, 2006(a)	2 Years		2-5 Years		5 Years		Collateral

Investment grade	$	631	$	69	$	—	$	700
Non-investment grade		12		—		—		12
No external ratings
Internally rated — investment grade		45		—		—		45
Internally rated — non-investment grade		5		—		—		5

Total	$	693	$	69	$	—	$	762


(a)		This table does not include accounts receivable exposure.

Collateral. As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

ISOs. Generation participates in the following established, real-time energy markets that are administered by ISOs: PJM, ISO New England, New York ISO, Midwest ISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation’s financial condition, results of operations or net cash flows.

Exelon

Exelon’s Consolidated Balance Sheet as of June 30, 2006 included a $518 million net investment in direct financing leases. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1,492 million, less unearned income of $974 million. The future minimum lease payments are supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps issued by high credit quality financial institutions. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases.

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

Variable Rate Debt. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital. At June 30, 2006, the Registrants did not have any fair-value or cash-flow interest-rate hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result

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in a $1 million decrease in Exelon’s pre-tax earnings for the three months ended June 30, 2006. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a decrease in pre-tax earnings for the three months ended June 30, 2006 of less than $1 million for ComEd, PECO and Generation.

Equity Price Risk (Exelon and Generation)

Generation maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of decommissioning Generation’s nuclear plants. As of June 30, 2006, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $419 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Policies and Estimates section within Exelon’s 2005 Annual Report onForm 10-K for information regarding the pension and other postretirement benefit trust assets.

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Item 4.	Controls and Procedures

During the second quarter of 2006, each registrant’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2006, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2006 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. They are also parties to regulatory proceedings in connection with efforts to secure the regulatory approvals needed to consummate the Merger. For information regarding material lawsuits and proceedings, see (a) ITEM 3. Legal Proceedings of the Registrants’ 2005 Annual Report onForm 10-K and (b) Notes 5 and 13 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.


Item 1A.	Risk Factors

At June 30, 2006, the Registrants’ risk factors did not change significantly from December 31, 2005, except for the following:

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Registrants operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal and are an important aspect of their operations. Violations of these emission and disposal requirements can subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation andclean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages. In addition, the Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies will be one component of such costs. Also, the Registrants are currently

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involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

In addition, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action, such as that proposed in The Fairness in Asbestos Injury Resolution Act of 2005, could require Generation to contribute to a fund with a material contribution to settle lawsuits for alleged asbestos-related disease and exposure.

For additional information regarding environmental matters, see Note 13 of the Combined Notes to Consolidated Financial Statements.

Exelon may have difficulty in successfully completing required divestitures following completion of the Merger.

On July 1, 2005, the FERC issued an order approving the Merger and the market concentration mitigation plan proposed by Exelon and PSEG. On June 22, 2006, Exelon and PSEG reached an agreement with the Antitrust Division of the United States Department of Justice (DOJ) which resolves all competition issues considered by DOJ in connection with the Merger. Although the agreement with DOJ has no effect if the Merger is not completed, the agreement requires Exelon to enter into contracts, within 150 days following the closing of the Merger, to sell six electricity generating plants now owned by subsidiaries of Exelon and PSEG representing an aggregate of approximately 5,600 MW of generation. Exelon, PSEG and the combined company may incur significant expenses in completing these divestitures. In addition, they may have difficulty in successfully completing the divestitures in the limited amount of time specified in the agreement with DOJ, and the amounts that may be realized from the divestitures will depend on market and other conditions that are unpredictable. As a result, the pricing and other terms realized on the divestitures may be materially different from what is currently expected. See Note 3 of Exelon’s Notes to Consolidated Financial Statements within Exelon’s 2005 Annual Report onForm 10-K for further information regarding the market concentration mitigation plan approved by the FERC. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the divestiture agreement reached with the DOJ.

The IRS might successfully challenge certain leveraged lease transactions entered into by PSEG, which could have a material adverse impact on the combined company’s operating results.

This risk factor related to the proposed Merger with PSEG was included in the Registrants’ 2005 Annual Report onForm 10-K. The Financial Accounting Standards Board recently issued two new pronouncements related to the accounting for uncertain tax positions and leveraged leases. Exelon is currently assessing the impact that this new guidance may have on the leveraged leases to be reported in its financial statements after the Merger. The impact of this new accounting guidance on the combined company could be material.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock in the quarter covered by this Report.

Maximum Number

(or Approximate

Total Number of

Dollar Value) of

Shares Purchased

Shares that May

Total Number

As Part of Publicly

Yet Be Purchased

of Shares

Average Price

Announced Plans

Under the Plans

Period

Purchased(a)

Paid per Share

or Programs(b)

or Programs

April 1 — April 30, 2006

19,697

52.84

—

)

May 1 — May 31, 2006

1,592

52.64

—

)

June 1 — June 30, 2006

1,503

56.83

—

)

Total

22,792

53.30

—

)

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(a)		Shares other than those purchased as part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares.

(b)		In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date.


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

Exelon

Exelon held its 2006 Annual Meeting of Shareholders on June 27, 2006 in Chicago, Illinois.

Proposal 1 was the election of five Class III directors to serve three-year terms expiring in 2009. The following directors were elected:


	Votes For		Votes Withheld

M. Walter D’Alessio		538,146,661		10,393,962
Rosemarie B. Greco		538,573,356		9,967,267
John M. Palms, Ph.D.		538,075,920		10,464,703
John W. Rogers, Jr.		537,978,858		10,561,765
Richard L. Thomas		537,741,898		10,798,725

Mr. Thomas will serve his term only until the closure of the Merger with PSEG. The following Class I directors will continue in office until their terms expire in 2007: Nicholas DeBenedictis, Sue L. Gin, Edgar D. Jannotta, William C. Richardson and Thomas J. Ridge. The following Class II directors will continue in office until their terms expire in 2008: Edward A. Brennan, Bruce DeMars, Nelson A. Diaz, John W. Rowe, and Ronald Rubin. Edgar D. Jannottta and Ronald Rubin will also only serve until the closure of the Merger with PSEG.

Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2006. The shareholders approved the proposal with a vote of 539,693,793 votes cast for, 3,730,251 votes cast against, and 5,116,579 votes abstaining.

Proposal 3 was a shareholder proposal urging the board of directors to seek shareholder approval of future severance benefits for senior executives. The board of directors recommended a vote against this proposal and it was not approved by the shareholders. It received 200,376,994 votes cast for and 260,431,063 votes against. There were also 9,185,352 votes abstaining and 78,547,214 broker non-votes.


Item 5.	Other Information

ComEd

On July 17, 2006, ComEd set a new record for highest daily peak load experienced to date of 23,295 megawatts.

PECO

On July 18, 2006, PECO set a new record for highest daily peak load experienced to date of 8,653 megawatts.

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Item 6.	Exhibits


Exhibit
No.		Description

	10-1	Hold Separate Stipulation and Order dated as of June 22, 2006 in U.S. v. Exelon Corporation and Public Service Enterprise Group Incorporated, U.S. Dist. Ct. for the District of Columbia (FileNo. 001-16169,Form 8-K dated June 22, 2006, Exhibit 99.1)
	10-2	Proposed Final Judgment dated as of June 22, 2006 in U.S. v. Exelon Corporation and Public Service Enterprise Group Incorporated, U.S. Dist. Ct. for the District of Columbia (FileNo. 001-16169,Form 8-K dated June 22, 2006, Exhibit 99.2)

Certifications Pursuant toRule 13a-14(a) and15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form10-Q for the quarterly period ended June 30, 2006 filed by the following officers for the following companies:


31-1	—	Filed by John W. Rowe for Exelon Corporation
31-2	—	Filed by John F. Young for Exelon Corporation
31-3	—	Filed by Frank M. Clark for Commonwealth Edison Company
31-4	—	Filed by Robert K. McDonald for Commonwealth Edison Company
31-5	—	Filed by John L. Skolds for PECO Energy Company
31-6	—	Filed by John F. Young for PECO Energy Company
31-7	—	Filed by John L. Skolds for Exelon Generation Company, LLC
31-8	—	Filed by John F. Young for Exelon Generation Company, LLC

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006 filed by the following officers for the following companies:


32-1	—	Filed by John W. Rowe for Exelon Corporation
32-2	—	Filed by John F. Young for Exelon Corporation
32-3	—	Filed by Frank M. Clark for Commonwealth Edison Company
32-4	—	Filed by Robert K. McDonald for Commonwealth Edison Company
32-5	—	Filed by John L. Skolds for PECO Energy Company
32-6	—	Filed by John F. Young for PECO Energy Company
32-7	—	Filed by John L. Skolds for Exelon Generation Company, LLC
32-8	—	Filed by John F. Young for Exelon Generation Company, LLC

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION





/s/ John W. Rowe John W. Rowe Chairman, Chief Executive Officer and President (Principal Executive Officer)		/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer (Principal Financial Officer)






/s/ Matthew F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller (Principal Accounting Officer)

July 31, 2006

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY





/s/ Frank M. Clark Frank M. Clark Chairman and Chief Executive Officer (Principal Executive Officer)		/s/ J. Barry Mitchell J. Barry Mitchell President



/s/ Robert K. McDonald Robert K. McDonald Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer (Principal Financial Officer)		/s/ Matthew F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

July 31, 2006

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Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY





/s/ John L. Skolds John L. Skolds President, Exelon Energy Delivery (Principal Executive Officer)		/s/ Denis P. O’Brien Denis P. O’Brien President



/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)		/s/ Matthew F. Hilzinger Matthew F. Hilzinger Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

July 31, 2006

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC





/s/ John L. Skolds John L. Skolds President (Principal Executive Officer)		/s/ John F. Young John F. Young Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)






/s/ Jon D. Veurink Jon D. Veurink Vice President and Controller (Principal Accounting Officer)

July 31, 2006

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