Edgar Filing: EXELON GENERATION CO LLC

June 30, 2009

Total
Environmental
Investigation and
Remediation
Reserve

Portion of Total Related
to MGP Investigation
and Remediation

Generation

Form 10-Q

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, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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

1-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398

333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959

1-1839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321

000-16844	PECO ENERGY COMPANY	23-0970240
000-16844	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

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 ¨.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company

Exelon Corporation	ü
Exelon Generation Company, LLC			ü
Commonwealth Edison Company			ü
PECO Energy Company			ü

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ.

The number of shares outstanding of each registrant’s common stock as of June 30, 2009 was:


Exelon Corporation Common Stock, without par value		659,079,914
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,519
PECO Energy Company Common Stock, without par value		170,478,507

TABLE OF CONTENTS


		Page No.

FILING FORMAT		3

FORWARD-LOOKING STATEMENTS		3

WHERE TO FIND MORE INFORMATION		3

PART I.	FINANCIAL INFORMATION	4

ITEM 1.	FINANCIAL STATEMENTS	4

	Exelon Corporation	5

	Consolidated Statements of Operations and Comprehensive Income	5

	Consolidated Statements of Cash Flows	6

	Consolidated Balance Sheets	7

	Consolidated Statement of Changes in Shareholders’ Equity	9

	Exelon Generation Company, LLC	10

	Consolidated Statements of Operations and Comprehensive Income	10

	Consolidated Statements of Cash Flows	11

	Consolidated Balance Sheets	12

	Consolidated Statement of Changes in Equity	14

	Commonwealth Edison Company	15

	Consolidated Statements of Operations and Comprehensive Income	15

	Consolidated Statements of Cash Flows	16

	Consolidated Balance Sheets	17

	Consolidated Statement of Changes in Shareholders’ Equity	19

	PECO Energy Company	20

	Consolidated Statements of Operations and Comprehensive Income	20

	Consolidated Statements of Cash Flows	21

	Consolidated Balance Sheets	22

	Consolidated Statement of Changes in Shareholders’ Equity	24

	Combined Notes to Consolidated Financial Statements	25

	1. Basis of Presentation	25

	2. New Accounting Pronouncements	27

	3. Regulatory Issues	31

	4. Property, Plant, and Equipment	42

	5. Intangible Assets	43

	6. Fair Value of Assets and Liabilities	44

	7. Debt and Credit Agreements	62

	8. Derivative Financial Instruments	63

	9. Retirement Benefits	77

	10. Severance Accounting	79


		Page No.

	11. Income Taxes	80

	12. Asset Retirement Obligations and Spent Nuclear Fuel Storage	85

	13. Earnings Per Share and Equity	90

	14. Commitments and Contingencies	91

	15. Supplemental Financial Information	103

	16. Segment Information	114

	17. Related-Party Transactions	116

	18. Subsequent Events	123

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	124

	Exelon Corporation	124

	General	124

	Executive Overview	124

	Critical Accounting Policies and Estimates	136

	Results of Operations	136

	Liquidity and Capital Resources	163

	Exelon Generation Company, LLC	178

	Commonwealth Edison Company	179

	PECO Energy Company	181

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	183

ITEM 4.	CONTROLS AND PROCEDURES	196

ITEM 4T.	CONTROLS AND PROCEDURES	196

PART II.	OTHER INFORMATION	197

ITEM 1.	LEGAL PROCEEDINGS	197

ITEM 1A.	RISK FACTORS	197

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	197

ITEM 6.	EXHIBITS	198

SIGNATURES		199

	Exelon Corporation	199

	Exelon Generation Company, LLC	199

	Commonwealth Edison Company	200

	PECO Energy Company	200

CERTIFICATION EXHIBITS

	Exelon Corporation	201, 209

	Exelon Generation Company, LLC	203, 211

	Commonwealth Edison Company	205, 213

	PECO Energy Company	207, 215

FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include (a) those factors discussed in the following sections of the Registrants’ 2008 Annual Report on Form 10-K: ITEM 1A. Risk Factors, as updated by Part II, ITEM 1A of this Report; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as updated by Part I, ITEM 2 of this Report; and ITEM 8. Financial Statements and Supplementary Data: Note 18, as updated by Part I, Item 1. Financial Statements, Note 14 of this Report; and (b) other factors discussed herein and in other filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2009			2008			2009			2008
Operating revenues	$	4,141		$	4,622		$	8,863		$	9,139
Operating expenses
Purchased power		921			1,166			1,604			2,239
Fuel		460			352			1,236			890
Operating and maintenance		1,110			1,080			2,472			2,273
Operating and maintenance for regulatory required programs		14			6			25			6
Depreciation and amortization		439			402			875			799
Taxes other than income		180			186			380			379

Total operating expenses		3,124			3,192			6,592			6,586

Operating income		1,017			1,430			2,271			2,553

Other income and deductions
Interest expense		(159	)		(180	)		(323	)		(361	)
Interest expense to affiliates, net		(21	)		(34	)		(44	)		(75	)
Equity in losses of unconsolidated affiliates and investments		(6	)		(8	)		(14	)		(13	)
Other, net		257			(40	)		219			(98	)

Total other income and deductions		71			(262	)		(162	)		(547	)

Income from continuing operations before income taxes		1,088			1,168			2,109			2,006
Income taxes		430			419			740			676

Income from continuing operations		658			749			1,369			1,330

Discontinued operations
Loss from discontinued operations (net of taxes of $0, $0, $0 and $0 for the three and six months ended June 30, 2009 and 2008, respectively)		(1	)		(1	)		—			—
Loss on disposal of discontinued operations (net of taxes of $0, $0, $0 and $(1) for the three and six months ended June 30, 2009 and 2008, respectively)		—			—			—			(1	)

Loss from discontinued operations, net		(1	)		(1	)		—			(1	)

Net income		657			748			1,369			1,329

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		2			(2	)		(6	)		(5	)
Actuarial loss reclassified to periodic cost		17			15			45			30
Transition obligation reclassified to periodic cost		—			—			1			1
Pension and non-pension postretirement benefit plans valuation adjustment		—			—			28			4
Change in unrealized gain (loss) on cash flow hedges		(220	)		(479	)		305			(952	)
Change in unrealized gain on marketable securities		8			—			5			—

Other comprehensive income (loss)		(193	)		(466	)		378			(922	)

Comprehensive income	$	464		$	282		$	1,747		$	407

Average shares of common stock outstanding:
Basic		659			657			659			658
Diluted		661			662			661			663

Earnings per average common share — basic:
Income from continuing operations	$	1.00		$	1.14		$	2.08		$	2.02
Loss from discontinued operations		—			—			—			—

Net income	$	1.00		$	1.14		$	2.08		$	2.02

Earnings per average common share — diluted:
Income from continuing operations	$	0.99		$	1.13		$	2.07		$	2.01
Loss from discontinued operations		—			—			—			—

Net income	$	0.99		$	1.13		$	2.07		$	2.01

Dividends per common share	$	0.53		$	0.50		$	1.05		$	1.00

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2009			2008
Cash flows from operating activities
Net income	$	1,369		$	1,329
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,253			1,096
Impairment of long-lived assets		223			—
Deferred income taxes and amortization of investment tax credits		149			99
Net fair value changes related to derivatives and nuclear decommissioning trust funds		(15	)		(149	)
Other non-cash operating activities		411			383
Changes in assets and liabilities:
Accounts receivable		286			94
Inventories		75			(40	)
Accounts payable, accrued expenses and other current liabilities		(404	)		(137	)
Counterparty collateral received (posted), net		246			(763	)
Income taxes		(177	)		277
Restricted cash		(2	)		11
Pension and non-pension postretirement benefit contributions		(68	)		(56	)
Other assets and liabilities		(299	)		(470	)

Net cash flows provided by operating activities		3,047			1,674

Cash flows from investing activities
Capital expenditures		(1,444	)		(1,511	)
Proceeds from nuclear decommissioning trust fund sales		10,150			10,515
Investment in nuclear decommissioning trust funds		(10,279	)		(10,679	)
Change in restricted cash		31			(22	)
Other investing activities		(4	)		(2	)

Net cash flows used in investing activities		(1,546	)		(1,699	)

Cash flows from financing activities
Issuance of long-term debt		485			1,969
Retirement of long-term debt		(255	)		(1,185	)
Retirement of long-term debt to financing affiliates		(330	)		(596	)
Change in short-term debt		(166	)		857
Dividends paid on common stock		(692	)		(659	)
Proceeds from employee stock plans		19			105
Purchase of treasury stock		—			(436	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)
Other financing activities		5			55

Net cash flows (used in) provided by financing activities		(934	)		46

Increase in cash and cash equivalents		567			21
Cash and cash equivalents at beginning of period		1,271			311

Cash and cash equivalents at end of period	$	1,838		$	332

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	1,838	$	1,271
Restricted cash and investments		46		75
Accounts receivable, net
Customer		1,536		1,928
Other		492		324
Mark-to-market derivative assets		627		410
Inventories, net
Fossil fuel		188		315
Materials and supplies		562		528
Other		536		517

Total current assets		5,825		5,368

Property, plant and equipment, net		26,305		25,813
Deferred debits and other assets
Regulatory assets		5,452		5,940
Nuclear decommissioning trust funds		5,850		5,500
Investments		691		670
Investments in affiliates		32		45
Goodwill		2,625		2,625
Mark-to-market derivative assets		663		507
Other		1,536		1,349

Total deferred debits and other assets		16,849		16,636

Total assets	$	48,979	$	47,817

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009			December 31, 2008
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	45		$	211
Long-term debt due within one year		413			29
Long-term debt to PECO Energy Transition Trust due within one year		390			319
Accounts payable		1,144			1,416
Mark-to-market derivative liabilities		294			214
Accrued expenses		1,045			1,151
Deferred income taxes		176			77
Other		659			663

Total current liabilities		4,166			4,080

Long-term debt		11,240			11,397
Long-term debt to PECO Energy Transition Trust		404			805
Long-term debt to other financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,260			4,939
Asset retirement obligations		3,841			3,734
Pension obligations		4,149			4,111
Non-pension postretirement benefit obligations		2,197			2,255
Spent nuclear fuel obligation		1,016			1,015
Regulatory liabilities		2,689			2,520
Mark-to-market derivative liabilities		74			24
Other		1,313			1,413

Total deferred credits and other liabilities		20,539			20,011

Total liabilities		36,739			36,683

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 659 and 658 shares outstanding at June 30, 2009 and December 31, 2008, respectively)		8,870			8,816
Treasury stock, at cost (35 and 35 shares held at June 30, 2009 and December 31, 2008, respectively)		(2,338	)		(2,338	)
Retained earnings		7,494			6,820
Accumulated other comprehensive loss, net		(1,873	)		(2,251	)

Total shareholders’ equity		12,153			11,047

Total liabilities and shareholders’ equity	$	48,979		$	47,817

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Issued Shares	Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance, December 31, 2008	692,953	$	8,816	$	(2,338	)	$	6,820		$	(2,251	)	$	11,047
Net income	—		—		—			1,369			—			1,369
Long-term incentive plan activity	895		54		—			—			—			54
Common stock dividends declared	—		—		—			(695	)		—			(695	)
Other comprehensive income, net of income taxes of $262	—		—		—			—			378			378

Balance, June 30, 2009	693,848	$	8,870	$	(2,338	)	$	7,494		$	(1,873	)	$	12,153

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2009			2008			2009			2008
Operating revenues
Operating revenues	$	1,545		$	1,922		$	3,202		$	3,525
Operating revenues from affiliates		833			834			1,777			1,713

Total operating revenues		2,378			2,756			4,979			5,238

Operating expenses
Purchased power		485			612			660			1,176
Fuel		406			271			915			542
Operating and maintenance		605			544			1,453			1,255
Operating and maintenance from affiliates		84			71			164			144
Depreciation and amortization		72			73			149			143
Taxes other than income		50			47			100			100

Total operating expenses		1,702			1,618			3,441			3,360

Operating income		676			1,138			1,538			1,878

Other income and deductions
Interest expense		(24	)		(38	)		(52	)		(74	)
Equity in losses of investments		—			(1	)		(1	)		(1	)
Other, net		215			(63	)		133			(128	)

Total other income and deductions		191			(102	)		80			(203	)

Income from continuing operations before income taxes		867			1,036			1,618			1,675
Income taxes		355			383			577			584

Income from continuing operations		512			653			1,041			1,091

Discontinued operations
Loss on disposal of discontinued operations (net of taxes of $0, $0, $0 and $0 for the three and six months ended June 30, 2009 and 2008, respectively)		—			—			—			(1	)

Loss from discontinued operations, net		—			—			—			(1	)

Net income		512			653			1,041			1,090

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans valuation adjustment		—			—			—			(3	)
Change in unrealized gain (loss) on cash flow hedges		(302	)		(596	)		657			(1,113	)

Other comprehensive income (loss)		(302	)		(596	)		657			(1,116	)

Comprehensive income (loss)	$	210		$	57		$	1,698		$	(26	)

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2009			2008
Cash flows from operating activities
Net income	$	1,041		$	1,090
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		526			440
Impairment of long-lived assets		223			—
Deferred income taxes and amortization of investment tax credits		100			144
Net fair value changes related to derivatives and nuclear decommissioning trust funds		(15	)		(98	)
Other non-cash operating activities		113			136
Changes in assets and liabilities
Accounts receivable		174			24
Receivables from and payables to affiliates, net		(47	)		(94	)
Inventories		1			(44	)
Accounts payable, accrued expenses and other current liabilities		(121	)		(88	)
Counterparty collateral received (posted), net		245			(832	)
Income taxes		(68	)		365
Pension and non-pension postretirement benefit contributions		(33	)		(25	)
Other assets and liabilities		(125	)		(262	)

Net cash flows provided by operating activities		2,014			756

Cash flows from investing activities
Capital expenditures		(801	)		(770	)
Proceeds from nuclear decommissioning trust fund sales		10,150			10,515
Investment in nuclear decommissioning trust funds		(10,279	)		(10,679	)
Change in restricted cash		11			11
Other investing activities		(7	)		(4	)

Net cash flows used in investing activities		(926	)		(927	)

Cash flows from financing activities
Change in short-term debt		—			1,087
Issuance of long-term debt		46			—
Retirement of long-term debt		(47	)		(2	)
Distribution to member		(675	)		(991	)
Other financing activities		2			1

Net cash flows (used in) provided by financing activities		(674	)		95

Increase (decrease) in cash and cash equivalents		414			(76	)
Cash and cash equivalents at beginning of period		1,135			127

Cash and cash equivalents at end of period	$	1,549		$	51

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	1,549	$	1,135
Restricted cash and cash equivalents		11		22
Accounts receivable, net
Customer		484		673
Other		120		108
Mark-to-market derivative assets		627		410
Mark-to-market derivative assets with affiliate		285		111
Receivables from affiliates		296		277
Inventories, net
Fossil fuel		95		143
Materials and supplies		466		435
Other		344		410

Total current assets		4,277		3,724

Property, plant and equipment, net		9,074		8,907
Deferred debits and other assets
Nuclear decommissioning trust funds		5,850		5,500
Investments		41		33
Receivable from affiliate		1		1
Mark-to-market derivative assets		652		490
Mark-to-market derivative assets with affiliate		753		345
Prepaid pension asset		906		949
Other		571		406

Total deferred debits and other assets		8,774		7,724

Total assets	$	22,125	$	20,355

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
LIABILITIES AND EQUITY
Current liabilities
Long-term debt due within one year	$	12	$	12
Accounts payable		695		792
Mark-to-market derivative liabilities		294		214
Payables to affiliates		51		78
Accrued expenses		578		761
Deferred income taxes		445		256
Other		324		324

Total current liabilities		2,399		2,437

Long-term debt		2,501		2,502
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,330		1,968
Asset retirement obligations		3,638		3,536
Pension obligations		—		63
Non-pension postretirement benefit obligations		649		576
Spent nuclear fuel obligation		1,016		1,015
Payables to affiliates		1,490		1,336
Mark-to-market derivative liabilities		73		24
Other		420		332

Total deferred credits and other liabilities		9,616		8,850

Total liabilities		14,516		13,789

Commitments and contingencies
Equity
Member’s equity
Membership interest		3,407		3,407
Undistributed earnings		2,689		2,323
Accumulated other comprehensive income, net		1,512		835

Total member’s equity		7,608		6,565
Noncontrolling interest		1		1

Total equity		7,609		6,566

Total liabilities and equity	$	22,125	$	20,355

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)


	Member’s Equity							Noncontrolling Interest		Total Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income		Noncontrolling Interest		Total Equity
Balance, December 31, 2008	$	3,407	$	2,323		$	835	$	1	$	6,566
Net income		—		1,041			—		—		1,041
Distribution to member		—		(675	)		—		—		(675	)
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes of $17		—		—			20		—		20
Other comprehensive income, net of income taxes of $435		—		—			657		—		657

Balance, June 30, 2009	$	3,407	$	2,689		$	1,512	$	1	$	7,609

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2009			2008			2009			2008
Operating revenues
Operating revenues	$	1,389		$	1,424		$	2,941		$	2,863
Operating revenues from affiliates		—			1			1			2

Total operating revenues		1,389			1,425			2,942			2,865

Operating expenses
Purchased power		368			494			812			950
Purchased power from affiliate		347			326			786			711
Operating and maintenance		224			231			433			437
Operating and maintenance from affiliate		46			43			89			86
Operating and maintenance for regulatory required programs		14			6			25			6
Depreciation and amortization		124			113			246			224
Taxes other than income		57			71			136			140

Total operating expenses		1,180			1,284			2,527			2,554

Operating income		209			141			415			311

Other income and deductions
Interest expense		(72	)		(83	)		(152	)		(178	)
Interest expense to affiliates, net		(3	)		(4	)		(7	)		(14	)
Equity in losses of unconsolidated affiliates		—			(3	)		—			(5	)
Other, net		55			5			87			9

Total other income and deductions		(20	)		(85	)		(72	)		(188	)

Income before income taxes		189			56			343			123
Income taxes		73			21			113			47

Net income		116			35			230			76

Other comprehensive income (loss), net of income taxes
Change in unrealized gain (loss) on marketable securities		7			(1	)		5			(2	)

Other comprehensive income (loss)		7			(1	)		5			(2	)

Comprehensive income	$	123		$	34		$	235		$	74

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six months Ended June 30,
(In millions)	2009			2008
Cash flows from operating activities
Net income	$	230		$	76
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		246			224
Deferred income taxes and amortization of investment tax credits		142			19
Other non-cash operating activities		159			108
Changes in assets and liabilities:
Accounts receivable		42			14
Inventories		(5	)		(3	)
Accounts payable, accrued expenses and other current liabilities		(89	)		151
Receivables from and payables to affiliates, net		(31	)		64
Income taxes		(73	)		26
Restricted cash		(2	)		11
Pension and non-pension postretirement benefit contributions		(6	)		(3	)
Other assets and liabilities		(32	)		(64	)

Net cash flows provided by operating activities		581			623

Cash flows from investing activities
Capital expenditures		(423	)		(505	)
Change in restricted cash		—			(50	)
Other investing activities		2			10

Net cash flows used in investing activities		(421	)		(545	)

Cash flows from financing activities
Changes in short-term debt		(15	)		(370	)
Issuance of long-term debt		191			1,325
Retirement of long-term debt		(208	)		(558	)
Retirement of long-term debt to financing trusts		—			(335	)
Dividends paid on common stock		(120	)		—

Net cash flows (used in) provided by financing activities		(152	)		62

Increase in cash and cash equivalents		8			140
Cash and cash equivalents at beginning of period		47			87

Cash and cash equivalents at end of period	$	55		$	227

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	55	$	47
Restricted cash		3		1
Accounts receivable, net
Customer		709		798
Other		157		162
Inventories, net		78		75
Regulatory assets		306		169
Deferred income taxes		57		32
Other		22		25

Total current assets		1,387		1,309

Property, plant and equipment, net		11,879		11,655
Deferred debits and other assets
Regulatory assets		1,228		858
Investments		36		34
Goodwill		2,625		2,625
Receivables from affiliates		1,420		1,291
Prepaid pension asset		800		847
Other		632		618

Total deferred debits and other assets		6,741		6,273

Total assets	$	20,007	$	19,237

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	45	$	60
Long-term debt due within one year		1		17
Accounts payable		256		307
Accrued expenses		309		306
Payables to affiliates		148		179
Customer deposits		124		119
Mark-to-market derivative liability with affiliate		285		111
Other		46		54

Total current liabilities		1,214		1,153

Long-term debt		4,708		4,709
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,539		2,369
Asset retirement obligations		178		174
Non-pension postretirement benefit obligations		246		203
Regulatory liabilities		2,590		2,440
Mark-to-market derivative liability with affiliate		752		345
Other		724		903

Total deferred credits and other liabilities		7,029		6,434

Total liabilities		13,157		12,502

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		4,982		4,982
Retained earnings		280		170
Accumulated other comprehensive loss, net		—		(5	)

Total shareholders’ equity		6,850		6,735

Total liabilities and shareholders’ equity	$	20,007	$	19,237

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Other Paid-In Capital		Retained (Deficit) Earnings Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive (Loss) Income			Total Shareholders’ Equity
Balance, December 31, 2008	$	1,588	$	4,982	$	(1,639	)	$	1,809		$	(5	)	$	6,735
Net income		—		—		230			—			—			230
Appropriation of retained earnings for future dividends		—		—		(230	)		230			—			—
Common stock dividends		—		—		—			(120	)		—			(120	)
Other comprehensive income, net of income taxes of $(2)		—		—		—			—			5			5

Balance, June 30, 2009	$	1,588	$	4,982	$	(1,639	)	$	1,919		$	—		$	6,850

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2009			2008			2009			2008
Operating revenues
Operating revenues	$	1,201		$	1,274		$	2,712		$	2,747
Operating revenues from affiliates		3			3			6			7

Total operating revenues		1,204			1,277			2,718			2,754

Operating expenses
Purchased power		67			85			132			164
Purchased power from affiliate		480			509			984			1,001
Fuel		55			80			321			348
Operating and maintenance		123			172			276			317
Operating and maintenance from affiliates		26			24			51			48
Depreciation and amortization		230			205			455			411
Taxes other than income		69			64			135			129

Total operating expenses		1,050			1,139			2,354			2,418

Operating income		154			138			364			336

Other income and deductions
Interest expense		(32	)		(28	)		(61	)		(55	)
Interest expense to affiliates, net		(17	)		(30	)		(38	)		(61	)
Equity in losses of unconsolidated affiliates		(6	)		(4	)		(12	)		(7	)
Other, net		3			7			6			11

Total other income and deductions		(52	)		(55	)		(105	)		(112	)

Income before income taxes		102			83			259			224
Income taxes		31			25			76			69

Net income		71			58			183			155
Preferred security dividends		1			1			2			2

Net income on common stock		70			57			181			153

Comprehensive income, net of income taxes
Net income		71			58			183			155
Other comprehensive income (loss), net of income taxes
Change in unrealized gain (loss) on marketable securities		1			(1	)		—			(1	)

Other comprehensive income (loss)		1			(1	)		—			(1	)

Comprehensive income	$	72		$	57		$	183		$	154

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2009			2008
Cash flows from operating activities
Net income	$	183		$	155
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		455			411
Deferred income taxes and amortization of investment tax credits		(102	)		(61	)
Other non-cash operating activities		83			90
Changes in assets and liabilities:
Accounts receivable		69			(31	)
Inventories		79			7
Accounts payable, accrued expenses and other current liabilities		(154	)		(41	)
Receivables from and payables to affiliates, net		64			54
Income taxes		51			77
Pension and non-pension postretirement benefit contributions		(16	)		(15	)
Other assets and liabilities		(128	)		(93	)

Net cash flows provided by operating activities		584			553

Cash flows from investing activities
Capital expenditures		(179	)		(206	)
Changes in Exelon intercompany money pool		(74	)		—
Change in restricted cash		2			2
Other investing activities		1			6

Net cash flows used in investing activities		(250	)		(198	)

Cash flows from financing activities
Issuance of long-term debt		248			644
Retirement of long-term debt		—			(604	)
Retirement of long-term debt to PECO Energy Transition Trust		(330	)		(261	)
Change in short-term debt		(95	)		(41	)
Dividends paid on common stock		(154	)		(236	)
Dividends paid on preferred securities		(2	)		(2	)
Repayment of receivable from parent		160			142

Net cash flows used in financing activities		(173	)		(358	)

Increase (decrease) in cash and cash equivalents		161			(3	)
Cash and cash equivalents at beginning of period		39			34

Cash and cash equivalents at end of period	$	200		$	31

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009		December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	200	$	39
Restricted cash		—		2
Accounts receivable, net
Customer		342		457
Other		61		39
Inventories, net
Fossil fuel		93		172
Materials and supplies		18		18
Deferred income taxes		72		78
Receivable from Exelon intercompany money pool		74		—
Prepaid utility taxes		115		—
Other		16		14

Total current assets		991		819

Property, plant and equipment, net		5,166		5,074
Deferred debits and other assets
Regulatory assets		2,240		2,597
Investments		16		15
Investments in affiliates		26		39
Receivables from affiliates		72		47
Other		596		578

Total deferred debits and other assets		2,950		3,276

Total assets	$	9,107	$	9,169

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—		$	95
Long-term debt to PECO Energy Transition Trust due within one year		390			319
Accounts payable		105			204
Accrued expenses		149			120
Payables to affiliates		208			144
Customer deposits		67			74
Other		42			25

Total current liabilities		961			981

Long-term debt		2,221			1,971
Long-term debt to PECO Energy Transition Trust		404			805
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,349			2,451
Asset retirement obligations		24			24
Non-pension postretirement benefit obligations		289			283
Regulatory liabilities		74			49
Other		145			152

Total deferred credits and other liabilities		2,881			2,959

Total liabilities		6,651			6,900

Commitments and contingencies
Preferred securities		87			87
Shareholders’ equity
Common stock		2,291			2,291
Receivable from parent		(340	)		(500	)
Retained earnings		416			389
Accumulated other comprehensive income, net		2			2

Total shareholders’ equity		2,369			2,182

Total liabilities and shareholder’s equity	$	9,107		$	9,169

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Receivable from Parent			Retained Earnings			Accumulated Other Comprehensive Income		Total Shareholders’ Equity
Balance, December 31, 2008	$	2,291	$	(500	)	$	389		$	2	$	2,182
Net income		—		—			183			—		183
Common stock dividends		—		—			(154	)		—		(154	)
Preferred security dividends		—		—			(2	)		—		(2	)
Repayment of receivable from parent		—		160			—			—		160
Other comprehensive loss, net of income taxes of $1		—		—			—			—		—

Balance, June 30, 2009	$	2,291	$	(340	)	$	416		$	2	$	2,369

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Exelon’s corporate operations, some of which are performed through its business services subsidiary, Exelon Business Services Company, LLC (BSC), provide Exelon’s subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts formula, which is a method that utilizes a combination of gross revenues, total assets, and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at June 30, 2009, as equity, and PECO’s preferred stock as preferred securities of subsidiary in the consolidated financial statements.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for Exelon SHC, LLC, of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial statements. AmerGen Energy Company, LLC (AmerGen), a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton Nuclear Power Station (Clinton), Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek). Effective January 8, 2009, AmerGen was dissolved and the operating licenses for Clinton, TMI and Oyster Creek were transferred to Generation, which continues to operate those plants.

Each of Generation’s, ComEd’s and PECO’s consolidated financial statements includes the accounts of their subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of June 30, 2009 and 2008 and for the three and six months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO (collectively, Registrants), include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. Certain prior year amounts within Operating Activities in Exelon’s and Generation’s Consolidated Statements of

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flows and in ComEd’s Consolidated Statements of Operations have been reclassified between line items for comparative purposes. The reclassifications did not affect net income or cash flows from operating activities of the Registrants. The December 31, 2008 Consolidated Balance Sheets were taken from audited financial statements. In accordance with Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events” (SFAS No. 165), the Registrants performed an evaluation of subsequent events for the accompanying financial statements and notes included in Part 1, ITEM I of this report through July 24, 2009, the date this Report was issued. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, Generation, ComEd and PECO included in ITEM 8 of their 2008 Annual Report on Form 10-K.

Variable Interest Entities (Exelon, Generation, ComEd and PECO)

Exelon’s consolidated financial statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Exelon or one of its subsidiaries as the primary beneficiary of the variable interest entity (VIE). 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 method of accounting.

Generation enters into power purchase agreements (PPAs) with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers, including ComEd and PECO. Generation accounts for its leases in accordance with SFAS No. 13, “Accounting for Leases” and determines whether long-term PPAs are leases pursuant to Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement is a Lease.” Several of Generation’s long-term PPAs have been determined to be operating leases which are not considered variable interests under the guidance of Financial Accounting Standards Board (FASB) Interpretation No. 46(R), “Consolidation of Variable Interest Entities” and FIN 46 (revised December 2003) (FIN 46-R). Generation’s PPAs that are not deemed to be operating leases are typically either non-derivatives or derivatives that qualify for the normal purchases and normal sales scope exception and are not subject to the requirements of SFAS No 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). Generation has evaluated these PPAs under the provisions of FIN 46-R and determined that it either has no variable interest in the PPA counterparties or, where Generation does have variable interests in PPA counterparties, it is not the primary beneficiary of these counterparties and, therefore, consolidation is not required. These conclusions are based on the following factors: the PPAs do not have residual value guarantees and purchase options, Generation has no equity investments in the counterparties and does not incur expected losses related to the loss of plant value, the PPAs were based on market terms at their inception and Generation does not bear any operational risk related to the plants. Generation’s financial exposure to its PPAs relates to its fixed capacity payments, which are disclosed in Note 14 — Commitments and Contingencies.

The financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC (ComEd Funding) and ComEd Transitional Funding Trust (CTFT), and the financing trusts of PECO, namely PECO Trust III, PECO Energy Capital Trust IV (PECO Trust IV) and PECO Energy Transition Trust (PETT),

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

are not consolidated in Exelon’s, ComEd’s and PECO’s financial statements pursuant to the provisions of FIN 46-R. ComEd Funding, CTFT and PETT were created for the sole purpose of issuing debt obligations to securitize intangible transition property of ComEd and PECO; and the other entities were created to issue mandatorily redeemable trust preferred securities. As of June 30, 2009, the only remaining VIE for ComEd is ComEd Financing III, as the other entities were dissolved during 2008.

ComEd and PECO have concluded that they are not the primary beneficiaries of their respective trusts because investors in the trusts’ securities, not ComEd and PECO, bear the risk of loss related to those securities. ComEd and PECO, as the sponsors of the financing trusts, are obligated to pay the operating expenses of the trusts. ComEd’s and PECO’s balance sheets include payable to affiliate amounts due to their respective financing trusts as well as investments in their respective trusts.

The maximum exposure to loss as a result of ComEd’s and PECO’s involvement with the financing trusts was $6 million and $26 million, respectively, at June 30, 2009 and $6 million and $39 million, respectively, at December 31, 2008. ComEd’s and PECO’s maximum exposure to loss is determined based on the current carrying value of investments made in the VIEs. ComEd’s and PECO’s estimated range of exposure to loss related to the financing trusts is any amount up to the current carrying value of investments made in the VIEs. ComEd and PECO have not provided any non-contractually required financial support to the trusts during the six months ended June 30, 2009 and 2008.

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

SFAS No. 160

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS No. 160). SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires that changes in a parent’s ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. SFAS No. 160 was applied prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which were applied retrospectively for all periods presented.

The adoption had no impact on Exelon’s consolidated financial statements. Generation reclassified its noncontrolling interest of consolidated subsidiary from mezzanine equity to equity in its Consolidated Balance Sheets and Statement of Changes in Equity for all periods presented. The noncontrolling interest is eliminated in Exelon’s Consolidated financial statements as it is owned by Exelon.

PECO reclassified preferred securities from shareholders’ equity to mezzanine equity within its Consolidated Balance Sheets for all periods presented. The dividends on PECO’s preferred securities are reflected in interest expense and have not been reflected separately on Exelon’s Statement of Operations and Comprehensive Income, as the amounts are not considered significant.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SFAS No. 141-R and FSP FAS 141(R)-1

In December 2007, the FASB issued SFAS No. 141-R, “Business Combinations” (SFAS No. 141-R) which revised SFAS No. 141, “Business Combinations”. This pronouncement became effective for the Registrants as of January 1, 2009. Under SFAS No. 141-R, transaction costs are required to be expensed as incurred. Additionally, adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of income tax expense, rather than goodwill. As a result of applying the provisions of SFAS No. 141-R, Exelon and ComEd recorded Illinois Replacement Investment Tax Credits (ITC) and interest benefits relating to uncertain tax positions from the period prior to the merger between PECO and Unicom Corporation of $25 million (after taxes) in the first quarter of 2009 as a benefit in the statement of financial position. See Note 11 — Income Taxes for further information.

In April 2009, the FASB issued FSP FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (FSP FAS 141(R)-1). This pronouncement amends SFAS No. 141-R to clarify the initial and subsequent recognition, subsequent accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP SFAS No. 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value at the acquisition date if it can be determined during the measurement period (not more than one year from the acquisition date). If the acquisition-date fair value of an asset or liability cannot be determined during the measurement period, the asset or liability will only be recognized at the acquisition date if it is both probable that an asset existed or liability has been incurred at the acquisition date, and if the amount of the asset or liability can be reasonably estimated. These conditions are to be applied in accordance with the guidance in FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5) and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss.” FSP FAS No. 141(R)-1 became effective for the Registrants as of January 1, 2009. As the provisions of FSP FAS 141(R)-1 are applied prospectively to business combinations with an acquisition date on or after the guidance became effective, the impact to the Registrants cannot be determined until the transactions occur. No such transactions have occurred during 2009.

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, by requiring enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 was effective for the Registrants as of January 1, 2009. As SFAS No. 161 provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 8 — Derivative Financial Instruments for further information.

FSP SFAS 132(R)-1

In December 2008, the FASB issued FSP FAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1), which requires additional disclosures for employers’ pension and other postretirement benefit plan assets. As pension and other postretirement benefit plan assets were not

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

included within the scope of SFAS No. 157, FSP FAS 132(R)-1 requires employers to disclose information about fair value measurements of plan assets similar to the disclosures required under SFAS No. 157, the investment policies and strategies for the major categories of plan assets, and significant concentrations of risk within plan assets. FSP FAS 132(R)-1 will be effective for the Registrants as of December 31, 2009. As FSP FAS 132(R)-1 provides only disclosure requirements, the adoption of this standard will not impact the Registrants’ results of operations, cash flows or financial positions.

FSP FAS 157-2 and FSP FAS 157-4

In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008. The pronouncement was effective for all Registrants as of January 1, 2009. See Note 6 — Fair Value of Assets and Liabilities for further information on the adoption of FSP FAS 157-2.

In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP FAS 157-4), which provides additional guidance for applying the provisions of SFAS No. 157. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This FSP requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and a significant adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (that is, not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. FSP FAS 157-4 was adopted for the period ending June 30, 2009. The adoption of FSP FAS 157-4 did not have a material impact to the Registrants’ results of operations, cash flows or financial positions.

FSP FAS 107-1 and APB 28-1

In April 2009, the FASB issued FSP FAS No. 107-1 and Accounting Principles Board (APB) 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” (SFAS No. 107) and APB Opinion No. 28, “Interim Financial Reporting,” respectively, to require disclosures about fair value of financial instruments in interim financial statements, in addition to the annual financial statements as already required by SFAS No. 107. FSP FAS 107-1 and APB 28-1 was adopted by the Registrants for the period ended June 30, 2009. As FSP FAS 107-1 and APB 28-1 provides only disclosure requirements, the application of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 6 — Fair Value of Assets and Liabilities for further information.

FSP FAS 115-2 and FAS 124-2

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2), which amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” and SFAS No. 124, “Accounting for Certain

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Investments Held by Not-for-Profit Organizations”. This standard establishes a different other-than-temporary impairment indicator for debt securities than previously prescribed. If it is more likely than not that an impaired security will be sold before the recovery of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in other comprehensive income and recognized over the remaining life of the debt security. In addition, the standard expands the presentation and disclosure requirements for other-than-temporary-impairments for both debt and equity securities. FSP FAS 115-2 and FAS 124-2 was adopted for the period ended June 30, 2009. FSP FAS 115-2 and FAS 124-2 did not have a material impact on the Registrants’ results of operations, cash flows, or financial positions. See Note 6 — Fair Value of Assets and Liabilities for further information.

SFAS No. 165

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (SFAS No. 165). SFAS No. 165 incorporates the principles and accounting guidance for recognizing and disclosing subsequent events that originated as auditing standards into the body of authoritative literature issued by the FASB as well as prescribes disclosure regarding the date through which subsequent events have been evaluated. The Registrants are required to evaluate subsequent events through the date the financial statements are issued. SFAS No. 165 was effective for the Registrants for the period ended June 30, 2009. As SFAS No. 165 is not intended to significantly change the current practice of reporting subsequent events, it did not have an impact on the Registrants’ results of operations, cash flows or financial positions. See Note 1 — Basis of Presentation for further information.

SFAS No. 166

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140” (SFAS No. 166). SFAS No. 166 amends current guidance for accounting for the transfers of financial assets. Key provisions of SFAS No. 166 include (i) the removal of the concept of qualifying special purpose entities, (ii) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred and (iii) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. Further, SFAS No. 166 requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. SFAS No. 166 is effective for the Registrants beginning January 1, 2010, and is required to be applied prospectively. The Registrants are currently assessing the impacts SFAS No. 166 may have on their financial statements.

SFAS No. 167

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. FIN 46(R)” (SFAS No. 167). SFAS No. 167 amends the manner in which entities evaluate whether consolidation is required for VIEs. A company must first perform a qualitative analysis in determining whether it must consolidate a VIE, and if the qualitative analysis is not determinative, must perform a quantitative analysis. Further, SFAS No. 167 requires that companies continually evaluate VIEs for consolidation, rather than assessing based upon the occurrence of triggering events. SFAS No. 167 also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. SFAS No. 167 is effective for the Registrants beginning January 1, 2010. The Registrants are currently assessing the impacts of SFAS No. 167. Information regarding the Registrants’ involvement with VIEs is included in Note 1 — Basis of Presentation.

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SFAS No. 168

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification (Codification) and the Hierarchy of GAAP” (SFAS No. 168), which replaces SFAS No. 162, “The Hierarchy of GAAP” and establishes the Codification as the single source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. SEC rules and interpretive releases are also sources of authoritative GAAP for SEC registrants. SFAS No. 168 modifies the GAAP hierarchy to include only two levels of GAAP: authoritative and nonauthoritative. SFAS No. 168 is effective beginning for periods ended after September 15, 2009. As SFAS No. 168 is not intended to change or alter existing GAAP, it will not impact the Registrants’ results of operations, cash flows or financial positions. Exelon will adjust historical GAAP references in its third quarter 2009 Form 10-Q to reflect accounting guidance references included in the codification.

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

Illinois Settlement Agreement (Exelon, Generation and ComEd). In July 2007, following extensive discussions with legislative leaders in Illinois, ComEd, Generation, and other utilities and generators in Illinois reached an agreement (Illinois Settlement) with various parties concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation reflecting the Illinois Settlement (Illinois Settlement Legislation) was signed into law in August 2007. The Illinois Settlement and the Illinois Settlement Legislation provide for the following, among other things:

Rate Relief Programs

•

Various Illinois electric utilities, their affiliates, and generators of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years (2007-2010) to programs to provide rate relief to Illinois electricity customers and funding for the Illinois Power Agency (IPA) created by the Illinois Settlement Legislation. ComEd and Generation committed to contributing $811 million to rate relief programs over the four year period and partial funding for the IPA. ComEd committed to issue $64 million in rate relief credits to customers or to fund various programs to assist customers. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, $307.5 million for rate relief programs for customers of other Illinois utilities and $4.5 million for partially funding operations of the IPA. The contributions are recognized in the financial statements of Generation and ComEd as rate relief credits are applied to customer bills by ComEd and other Illinois utilities, or as operating expenses associated with the programs are incurred.

During the three and six months ended June 30, 2009, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement in their Consolidated Statements of Operations as follows:


Three Months Ended June 30, 2009	Generation		ComEd		Total credits issued to ComEd customers
Credits to ComEd customers(a)	$	17	$	2	$	19
Credits to other Illinois utilities’ customers(a)		13		n/a		n/a

Total incurred costs	$	30	$	2	$	19

(a)	Recorded as a reduction in operating revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2009	Generation		ComEd		Total credits issued to ComEd customers
Credits to ComEd customers(a)	$	37	$	2	$	39
Credits to other Illinois utilities’ customers(a)		26		n/a		n/a
Other rate relief programs(b)		—		1		n/a

Total incurred costs	$	63	$	3	$	39

(a)	Recorded as a reduction in operating revenues.

(b)	Recorded as a charge to operating and maintenance expense.

During the three and six months ended June 30, 2008, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement in their Consolidated Statements of Operations as follows:


Three Months Ended June 30, 2008	Generation		ComEd		Total credits issued to ComEd customers
Credits to ComEd customers(a)	$	46	$	2	$	48
Credits to other Illinois utilities’ customers(a)		24		n/a		n/a

Total incurred costs	$	70	$	2	$	48

(a)	Recorded as a reduction in operating revenues.


Six Months Ended June 30, 2008	Generation		ComEd		Total credits issued to ComEd customers
Credits to ComEd customers(a)	$	96	$	3	$	99
Credits to other Illinois utilities’ customers(a)		47		n/a		n/a
Other rate relief programs(b)		—		4		4

Total incurred costs	$	143	$	7	$	103

(a)	Recorded as a reduction in operating revenues.

(b)	Recorded as a charge to operating and maintenance expense.

As of June 30, 2009, Generation’s remaining costs to be recognized related to the rate relief commitment are $55 million, consisting of $21 million related to programs for ComEd customers and $34 million for programs for customers of other Illinois utilities. ComEd’s remaining costs to be recognized related to the rate relief commitment are $8 million as of June 30, 2009.

Energy Efficiency and Renewable Energy

•

Electric utilities are required to include cost-effective energy efficiency resources in their plans to meet incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which is increasing annually to 2% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the Illinois Commerce Commission

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(ICC). In February 2008, the ICC issued an order approving substantially all of ComEd’s Energy Efficiency and Demand Response Plan, including cost recovery. This plan began in June 2008 and is designed to meet the Illinois Settlement Legislation’s energy efficiency and demand response goals for an initial three-year period, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers. During the three and six months ended June 30, 2009, expenses related to energy efficiency and demand response programs consisted of $13 million and $23 million, respectively. During the three and six months ended June 30, 2008, expenses related to these programs consisted of $5 million.

•

Since June 1, 2008, utilities have been required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with a goal of 25% by June 1, 2025, subject to customer rate cap limitations. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. Under the May 2008 ICC-approved request for proposal (RFP), ComEd began procuring renewable energy credits (RECs) beginning June 2008. On May 13, 2009, the ICC approved the results of an RFP to procure RECs for the period June 2009 through May 2010. ComEd currently retires all RECs immediately upon purchase. ComEd recovers procurement costs of RECs through rates, beginning in June 2008. See Note 14 — Commitments and Contingencies for further information regarding ComEd’s procurement of RECs.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). Beginning January 1, 2007, ComEd procured 100% of its load through staggered supplier forward contracts with various suppliers, including Generation. The supplier forward contracts resulted from an ICC-approved “reverse-auction” competitive bidding process, which permitted ComEd to recover its electricity procurement costs from retail customers without markup. The price for full requirements electric supply that resulted from the first auction was fixed through May 2008, at which time the auction contracts for one-third of the load expired. The auction contracts for an additional one-third of the load expired in May 2009 with auction contracts for the final third of the load expiring in May 2010.

The IPA, under the oversight of the ICC, participates in the design of an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply resources for deliveries in the supply period which began in June 2009. During the interim, the ICC approved a plan under which ComEd procured power for the period from June 2008 through May 2009.

In March 2008, ComEd completed its first RFP and the ICC voted to approve the lowest-cost package of bids received as recommended by the procurement administrator. ComEd’s purchases acquired through the RFP represented approximately 14% of its expected energy needs from June 2008 through May 2009. For the same period, approximately 19% of ComEd’s energy load was purchased on the spot market and is hedged with a variable to fixed financial swap with Generation. The remaining energy for the period came from the supplier forward contracts. See Note 8 — Derivative Financial Instruments for further discussion on the financial swap derivative.

The ICC has also initiated a proceeding to reconcile the actual costs of power purchased in the January 2007 through May 2008 period with the costs for power that flowed through ComEd’s tariffs and were collected from customers. Since the Illinois Settlement Legislation has already deemed such costs to be prudently incurred, the reconciliation proceeding is not expected to have a significant impact on ComEd.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On January 7, 2009, the ICC approved the IPA’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010, which includes approximately 38% of ComEd’s expected energy requirements purchased through the spot market with a significant portion of the purchases hedged by the financial swap contract with Generation, 33% being met through existing supplier forward contracts and the remaining energy requirements being met through the standard products purchased as a result of the 2009 RFP process completed in May 2009. Approximately 8% of ComEd’s energy requirements from June 2010 through May 2011 were also procured through the contracts entered into as a result of the 2009 RFP process. See Note 8 — Derivative Financial Instruments for further discussion on the financial swap derivative, and Note 14 — Commitments and Contingencies for further information regarding ComEd’s procurement of energy.

2005 Rate Case (Exelon and ComEd). In August 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007 (2005 Rate Case). ComEd proposed a revenue increase of $317 million. During 2006, the ICC issued various orders associated with this case, which resulted in a total annual rate increase of $83 million effective January 2007. ComEd and various other parties have appealed the rate order to the courts. ComEd cannot predict the result or the timing of the appeal. In the event the order is ultimately changed, the changes are expected to be prospective.

Original Cost Audit (Exelon and ComEd). In connection with ComEd’s 2005 Rate Case proceeding, the ICC, with ComEd’s concurrence, ordered an “original cost” audit of ComEd’s distribution assets. In December 2007, the consulting firm completed the audit. The consulting firm’s results of the audit were reported to the ICC in April 2008, which presented its findings regarding accounting methodology, documentation and other matters, along with proposed adjustments. The audit report recommended gross plant disallowances of approximately $350 million, before reflecting accumulated depreciation. The basis for the disallowance recommendation on approximately $80 million of the costs was that the assets were misclassified between ComEd’s distribution and transmission operations; ComEd reclassified these costs in September 2007 and they were reflected correctly in ComEd’s rate case filed in October 2007 (2007 Rate Case).

In April 2008, ComEd and the ICC Staff reached a stipulation (the stipulation) regarding various portions of contested issues in the Original Cost Audit as well as the 2007 Rate Case and agreed to make various joint recommendations to the ICC in the 2007 Rate Case. In September 2008, the ICC issued an order in the 2007 Rate Case, which incorporated the joint recommendations made by the ICC Staff and ComEd and required ComEd to incur a charge of approximately $19 million (pre-tax) related to various items identified in the Original Cost Audit.

The ICC opened a proceeding on the Original Cost Audit in May 2008. There is a tentative timeline for resolution of this proceeding during the second half of 2009. Under the terms of the stipulation, the ICC Staff will not advocate that any of the proposed adjustments in the audit report be adopted other than those reflected in the 2007 Rate Case; however, the stipulation does not preclude other parties to the rate case or to the Original Cost Audit proceeding from taking positions contrary to the stipulation. The Illinois Attorney General submitted testimony suggesting that ComEd improperly changed the way it capitalized cable faults during the rate freeze period and appears to suggest a corresponding reduction to rate base. ComEd filed testimony disputing these contentions and the ICC Staff filed testimony consistent with ComEd’s position in the proceeding.

ComEd believes the remainder of the consulting firm’s findings and the testimony of the Illinois Attorney General are without merit. However, the ultimate resolution of the audit after reflecting the appropriate associated accumulated depreciation and deferred income taxes associated with any such disallowances could result in a material disallowance and related write-off of a portion of the original cost of ComEd’s delivery service assets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2007 Rate Case (Exelon and ComEd). ComEd filed the 2007 Rate Case with the ICC for approval to increase its delivery service revenue requirement by approximately $360 million. The ICC issued an order in the rate case approving a $274 million increase in ComEd’s annual revenue requirement, which became effective in September 2008. ComEd and several other parties have filed appeals of the rate order with the courts. ComEd cannot predict the timing of resolution or the results of the appeals. In the event the order is ultimately changed, the changes are expected to be prospective.

The filing also included a system modernization rider, which the ICC approved for the limited purpose of implementing a pilot program for Advanced Metering Infrastructure (AMI). The rider would permit investments in AMI to be reflected in rates on a quarterly basis instead of waiting for the next rate case to begin recovery. On June 1, 2009, ComEd filed its proposed AMI pilot program with the ICC, which included revisions to the system modernization rider. The AMI pilot program will allow ComEd to study the costs and benefits related to automated metering in terms of remote disconnect and outage restoration. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. ComEd cannot predict the ICC’s ultimate decision related to the AMI pilot program or the revisions to the systems modernization rider at this time. Additionally, ComEd can not estimate the costs of a full system-wide implementation of AMI.

Transmission Rate Case (Exelon and ComEd). ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis. The settlement agreement provides for a base return on equity (ROE) on transmission rate base of 11.5%, except for ComEd’s largest transmission project which was allowed a return of 13%, a cap of 58% on the equity component of ComEd’s capital structure, which will decline to 55% by 2011, and a debt-only return based on ComEd’s long-term cost of debt on ComEd’s pension asset.

In May 2008, ComEd filed its first annual formula update filing, which updated ComEd’s formula rate to include actual 2007 expenses and investment plus forecasted 2008 capital additions. The update resulted in a revenue requirement of $430 million, plus an additional $26 million related to the 2007 true-up of actual costs, which was effective for the period June 1, 2008 through May 31, 2009. The regulatory asset associated with the true-up was amortized as the associated revenues were received.

On May 15, 2009 ComEd filed its second annual formula update to include actual 2008 expenses and investments plus forecasted 2009 capital additions. The update resulted in a revenue requirement of $436 million resulting in an increase of approximately $6 million from the 2008 revenue requirement, plus an additional $4 million related to the 2008 true-up of actual costs. The 2009 revenue requirement of $440 million, which includes the 2008 true-up, became effective June 1, 2009 and is recorded over the period extending through May 31, 2010. The regulatory asset associated with the true-up is being amortized as the associated revenues are received. ComEd will continue to reflect its best estimate of its anticipated true-up in the financial statements.

Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd). Comprehensive legislation has been enacted in Illinois which provides utilities the ability to adjust their rates annually through a rider mechanism to reflect the increases or decreases in annual uncollectible accounts expenses starting with 2008 and prospectively. ComEd under collected approximately $26 million during 2008 and approximately $4 million during the six months ended June 30, 2009. ComEd expects to file, in the third quarter, a tariff to begin collecting

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

past due amounts from 2008 in 2010. The ICC has 180 days to approve or modify and approve ComEd’s proposed tariff. ComEd does not know what modifications or conditions, if any, the ICC may include in a proposed tariff at this time.

Upon ICC approval of a tariff, ComEd will be required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund (the Fund). The Fund is used to assist low-income residential customers. As one way to assist such customers, the legislation creates a new percentage of income program (PIP) which includes an arrearage reduction component for participating customers. The program will be paid for from the Fund and other state monies.

ComEd currently anticipates that the potential benefit and the $10 million one-time charge will not be recorded until an actual tariff is approved by the ICC. If the tariff is approved, ComEd will record a regulatory asset and an offsetting reduction in operating and maintenance expense for the cumulative under collections from 2008 through the date of recognition. Recovery of the initial regulatory asset would take place over an approximate 17 month time frame assuming the tariff is approved by February 1, 2010.

Pennsylvania Gas Distribution Rate Case (Exelon and PECO). In October 2008, the Pennsylvania Public Utility Commission (PAPUC) voted to approve the joint settlement related to PECO’s March 2008 filing providing for an increase of $77 million to its annual natural gas distribution revenue. As part of the settlement, PECO agreed to enhance its low-income programs as well as provide funding for new energy-efficiency programs to help customers manage their energy usage and gas bills. Additionally, PECO agreed not to file a new base rate case for natural gas distribution service before January 1, 2010. The approved rate adjustment became effective on January 1, 2009.

Pennsylvania Transition-Related Legislative and Regulatory Matters (Exelon, Generation and PECO). In Pennsylvania, despite the recent decline in wholesale electricity market prices, there has been continuing pressure from state regulators and elected officials to mitigate the potential impact of electricity price increases on customers. While PECO’s retail electric generation rate cap transition period does not end until December 31, 2010, transition periods have ended for six other Pennsylvania electric distribution companies, and, in most instances, post-transition electric generation price increases occurred. Over the past few years, elected officials in Pennsylvania have worked on developing legislation to address the Pennsylvania Governor’s energy plan as well as the concerns over post-transition electric price increases. Measures suggested by legislators include rate-cap extensions, rate-increase deferrals and phase-ins, a generation tax and contributions of value (potentially billions of dollars statewide) by Pennsylvania utility companies toward rate-relief programs.

In October 2008, Act 129 of 2008 (Act 129) was signed into law. Act 129 provided guidelines associated with electricity procurement that support competitive, market-based procurement with a mix of spot market purchases, short-term and long-term contracts. Under Act 129, PECO is required to transition its electric customers to smart-meter technology over a fifteen-year period and to make available time-of-use rates and real-time price plans. The smart meter provisions require electric companies with at least 100,000 customers to file smart meter technology procurement and installation plans by August 14, 2009 for PAPUC approval. Each plan must set forth the company’s current deployment of smart meter technology, if any, and a plan for future deployment, complete with dates for key milestones and measurable goals. The legislation allows recovery of costs for each of these programs, subject to approval by the PAPUC.

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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On March 12, 2009, the PAPUC approved the settlement of PECO’s Market Rate Transition Phase-In Program. The program allows eligible residential and small-business electric-service customers to transition to market-priced generation through pre-payments made through 2010 that will accrue interest at the statutory rate of 6% and then be applied as credits to their bills in 2011 and 2012.

Pursuant to Act 129’s energy efficiency and conservation/demand (EE&C) reduction targets, PECO filed its EE&C plan with the PAPUC on July 1, 2009. The plan set forth how PECO will reduce electric consumption by at least 1% in its service territory by May 31, 2011 from expected consumption for the period June 1, 2009 through May 31, 2010, adjusted for weather and extraordinary loads, and by 3% by May 31, 2013. In accordance with Act 129, by May 31, 2013, PECO also plans to reduce peak demand by a minimum of 4.5% of PECO’s annual system peak demand in the 100 hours of highest demand, measured against its peak demand during the period of June 1, 2007 through May 31, 2008. If PECO fails to achieve the required reductions in consumption within stated deadlines, PECO will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of any EE&C plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006.

On June 18, 2009, the PAPUC finalized its rules for smart meter technology procurement and installation plans. The PAPUC’s rules provide a period of up to 30 months from plan approval for each electric distribution company to assess its needs, select smart meter technology and vendors, and install, test and begin deploying smart meters. PECO’s total capital costs for smart meter technology investments are estimated to be up to $650 million over 15 years, subject to PAPUC approval. In order to offset some of these costs, PECO will file its intent to seek federal matching funds under the American Recovery and Reinvestment Act of 2009 for eligible smart grid investments, including initial deployment of smart meter technology under Act 129. No assurance can be given that PECO will receive any Federal matching funds.

On June 9, 2009, the PAPUC’s formal investigation order was entered, instituting an investigation of whether PECO’s nuclear decommissioning cost adjustment clause, which is the mechanism that allows PECO to recover costs from customers for the decommissioning of six former PECO nuclear units now owned by Generation, should continue after the termination of PECO’s competitive transition cost collections on December 31, 2010, and assigning the matter for alternative dispute resolution or the prompt scheduling of such hearings as may be necessary. See Note 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information.

Pennsylvania Procurement Proceedings (Exelon and PECO). On June 2, 2009, the PAPUC entered a formal opinion and order approving the settlement of PECO’s default service provider program (DSP Program), under which PECO will provide default electric service following the expiration of electric generation rate caps on December 31, 2010. The DSP Program, which has a 29-month term, beginning January 1, 2011 and ending May 31, 2013, complies with electric generation procurement guidelines set forth in Act 129. Under the settlement, PECO will also expand its low-income assistance initiatives and offer a market rate deferral program under which certain customers can elect to phase-in, with interest, any post-electric generation rate cap increases in 2011 if they exceed 25%.

PECO’s default electric service customers have been divided into four procurement classes: a Residential class, a Small Commercial class (for non-residential customers with peak demand up to 100 kilowatts (kW)), a Medium Commercial class (for non-residential customers with peak demand of greater than 100 kW up to 500 kW), and a Large Commercial and Industrial class for non-residential customers with peak demand in excess of 500 kW.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Seventy-five percent of the Residential class, 90% of the Small Commercial class and 85% of the Medium Commercial class load will be served through competitively procured contracts for load-following, full requirements default electric generation for terms of two years or less. For the remaining portion of the Residential class load, PECO will competitively procure forward purchases of energy blocks (representing 20% of the load) and will balance the remaining load through sales and purchases of energy in the PJM day-ahead wholesale “spot” energy market (spot market). For the remaining portion of the Small Commercial and Medium Commercial class loads, as well as the Large Commercial and Industrial class load, PECO will competitively procure contracts for load-following, full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In addition, PECO will offer Large Commercial and Industrial customers a fixed-price optional service during the first year of PECO’s default service provider plan.

On June 15, 2009, PECO concluded the first of its competitive procurements for electric generation for default electric customers commencing January 2011, and on June 17, 2009, the PAPUC approved the results of the RFP process. The June 2009 procurements were for service to the Residential class and included full requirements fixed price contracts to procure eight tranches for the period beginning January 1, 2011 and ending May 31, 2012, four tranches for the period beginning January 1, 2011 and ending May 31, 2013 and block contracts to procure 40 megawatts (MW) for the period beginning January 1, 2011 and ending December 31, 2011. PECO will be participating in additional procurement RFPs in accordance with the plan approved by the PAPUC.

Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the Alternative Energy Portfolio Standards Act (AEPS Act). The AEPS Act mandated that beginning in 2007, or following the end of an electric distribution company’s retail electric generation rate cap transition period, certain percentages of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers shall be generated from certain alternative energy resources, as measured in alternative energy credits (AECs). The requirement for electric energy that must come from Tier I alternative energy resources (including solar or wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy generated within Pennsylvania and coal mine methane) ranges from 1.5% to 8.0% and the requirement for Tier II alternative energy resources (including waste coal, biomass energy generated outside of Pennsylvania, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification technology) ranges from 4.2% to 10.0%. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129, in addition to those outlined in the AEPS Act. The AEPS Act mandates the 8.0% requirement for Tier I resources and the 10.0% requirement for Tier II resources must be met by the year ending May 31, 2021.

The Pennsylvania Legislature is currently considering House Bill No. 80 (HB 80), which, if enacted into law, would increase the minimum required percentage of electric energy purchased and sold to retail electric customers from alternative energy resources and extend the period for such purchases and sales. HB 80 would expand the solar purchase and sale requirements and would incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource. Generation has proposed amendments to include extended nuclear uprates as a qualifying alternative energy source.

In 2007, the PAPUC approved PECO’s plan to acquire and bank approximately 450,000 non-solar Tier I AECs (corresponding to the expected annual output of approximately 240 MWs of wind power) annually for a

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

five-year term in order to prepare for 2011, the first year of PECO’s required compliance following the completion of its electric generation rate cap transition period. The banked AECs may be used in either of the two consecutive AEPS reporting periods after PECO’s electric generation rate cap transition period. All costs incurred in connection with AEC procurement prior to 2011 will be deferred as a regulatory asset with a return on the unamortized balance and will be recovered from customers in 2011. Those costs, and PECO’s AEPS Act compliance costs incurred thereafter, will be recovered from customers on a full and current basis through a reconcilable ratemaking mechanism as contemplated by the AEPS Act. In conformance with the plan approved in December 2007, PECO conducted two RFPs during 2008. Pursuant to the first RFP process, PECO entered into a five-year agreement in August 2008 with an accepted bidder for the purchase of 40,000 AECs annually. In April 2009, PECO entered into agreements with accepted bidders, including Generation, for the purchase of 412,000 AECs annually for five years beginning no later than December 31, 2009.

On March 3, 2009, PECO filed a petition with the PAPUC for expedited approval of its early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. PECO’s proposed procurement would employ the same surcharge cost-recovery mechanism that the PAPUC previously approved for non-solar Tier 1 AECs. On July 2, 2009, PECO and various interveners filed a joint petition for settlement of the case that provides for no cap on bid price, provides the PAPUC a 10 calendar day review period, permits facilities capable of generating a minimum of 300 AECs annually to bid and provides that no changes to the agreement with AEC suppliers will be accepted after PAPUC approval.

PJM-MISO Regional Rate Design (Exelon, ComEd and PECO). The current PJM-MISO Regional Rate Design is used to specify the pricing of transmission service between PJM and Midwest Independent Transmission System Operator, Inc. (MISO) and impacts ComEd and PECO due to purchases by suppliers from MISO. In August 2007, ComEd and PECO and several other transmission owners in PJM and MISO, as directed by a FERC order, filed with FERC to continue the existing transmission rate design between PJM and MISO. Additional transmission owners and certain other entities filed protests urging FERC to reject the filing. In September 2007, a complaint was filed asking FERC to find that the PJM-MISO rate design was unjust and unreasonable and to substitute a rate design that socializes the costs of all existing and new transmission facilities of 345 kV and above across PJM and MISO. In December 2008, FERC denied a request for rehearing of these orders and an appeal has been filed in the United States Court of Appeals. ComEd and PECO cannot predict the outcome of this litigation.

Authorized Return on Rate Base (Exelon, ComEd and PECO). In the September 2008 order in the 2007 Rate Case, the ICC authorized a return on ComEd’s distribution rate base using a weighted average debt and equity return of 8.36%. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, ComEd’s formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.43%, which is exclusive of the incentive ROE on ComEd’s largest transmission project. The weighted average debt and equity return on transmission rate base will be updated annually in accordance with the formula-based rate calculation discussed above.

PECO’s transition period includes caps on electric generation rates that will expire on December 31, 2010 pursuant to the Pennsylvania Electric Generation Customer Choice and Competition Act (Competition Act). The distribution and transmission components of PECO’s rates will continue to be regulated subsequent to the transition period. PECO’s most recently approved weighted average debt and equity return on electric rate base was 11.23% (approved in 1990). PECO’s gas rates are not subject to caps. As part of the gas distribution rate case filed in March 2008, PECO requested that the PAPUC authorize it to establish base rates for natural gas

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

distribution service using a weighted average debt and equity return on gas rate base of 8.90%. The joint settlement petition in that matter, approved in October 2008 by the PAPUC, did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. Prior to the 2008 gas distribution rate case, the most recently approved weighted average debt and equity return on gas rate base was 11.45% (approved in 1988).

Market-Based Rates (Exelon, Generation, ComEd and PECO). Generation, ComEd and PECO are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd and PECO have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd or PECO has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

In June 2007, FERC issued a Final Rule on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities (Order No. 697), which updated and modified the tests that FERC had implemented in 2004. That order was clarified in December 2007, largely affirmed in April 2008 in Order No. 697-A, further clarified in July 2008, where the calculation of one of the variables used in FERC’s screening tests was explained and further clarified and largely affirmed in December 2008 in Order No. 697-B, and further clarified in June 2009 in Order No. 697-C. The Registrants do not expect that the Final Rule will have a material effect on their results of operations in the short-term. The longer-term impact will depend on the future application by FERC of Order Nos. 697 and future actions involving market-based rates.

In March 2008, the ICC intervened in the proceeding and in September 2008 filed a protest. In its protest, the ICC did not object to Exelon’s request for continued authority to make market-based sales. Instead, the ICC repeated its contentions in an earlier docket in which ComEd had asked FERC to affirm that the procurement for its customers for the period June 1, 2008 through May 31, 2009 satisfied FERC standards, the ICC contended that existing waivers of FERC’s affiliate transaction rules should no longer apply between ComEd and its affiliates, including Generation, because ComEd has captive retail customers. In its response, Exelon reminded FERC that the ICC’s contention was the same as in the earlier ComEd procurement proceeding in which FERC had rejected the ICC’s position. Exelon also noted that the facts on which FERC based its previous finding have not changed.

On January 15, 2009, FERC accepted Exelon’s analysis and filing, affirming Exelon’s affiliates’ continued right to make sales at market-based rates. FERC also rejected an ICC request for rehearing in the earlier ComEd procurement docket, in which the ICC had also asked FERC to reconsider its determination in that proceeding that the existing waiver of the affiliate restrictions should not be revoked.

In December 2008, Generation filed an analysis for generation in the Southeast region covering generation in the Southern Company and Entergy areas using FERC’s updated screening tests, as required by the Final Rule. In June 2009, Generation filed an analysis for generation in the Central region covering generation in the Midwest Independent Transmission System Operator market using FERC’s updated screening tests, also as required by the Final Rule. These analyses demonstrated that Exelon does not have market power in those areas and, therefore, is entitled to continue to sell at market-based rates in them.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reliability Pricing Model (RPM) (Exelon and Generation). On August 31, 2005, PJM submitted a proposal to FERC for a new capacity payment construct to replace PJM’s then-existing capacity obligation rules. The proposal provided for a forward capacity procurement auction to establish capacity and payment obligations using a demand curve and locational deliverability zones for capacity. The FERC affirmed PJM’s proposal for forward commitments and other matters but encouraged PJM and the parties to that FERC proceeding to resolve other RPM issues by settlement. A settlement was reached on September 29, 2006 and was approved by FERC on December 22, 2006. The settlement provided for an auction 36 months in advance of each delivery year beginning with the delivery year ending May 31, 2012 and an expedited phase-in process for four transitional auctions covering delivery years ending on May 31 in 2008 through 2011. All but one appeal for FERC’s order approving RPM were withdrawn on February 27, 2009 and the remaining appeal was denied by the Court of Appeals for the D.C. Circuit on March 17, 2009.

PJM’s four transitional RPM auctions took place in April 2007, July 2007, October 2007 and January 2008 and established prices for the period from June 1, 2007 through May 31, 2011. Subsequent auctions will take place 36 months ahead of the scheduled delivery year. The auction for the delivery year ending May 31, 2012 and May 31, 2013 occurred in May 2008 and May 2009, respectively. The RPM is anticipated to have a favorable impact for owners of generation facilities, particularly for such facilities located in constrained zones. PJM is authorized to impose PJM RPM capacity penalties.

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by FERC that established RPM. In the complaint, the RPM Buyers requested that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On September 19, 2008, FERC dismissed the complaint finding that no party violated PJM’s tariff and the prices determined during the initial auctions implementing the RPM were in accord with the tariff provisions governing the auctions. On June 18, 2009, FERC denied the RPM Buyers’ request for rehearing of FERC’s September 19, 2008 order. This order may be subject to review by a Federal Court of Appeals. If a Federal Court of Appeals were to reverse FERC’s decision, FERC would be required to conduct additional proceedings regarding the substantive allegations in the complaint. Generation believes that it is remote that the ultimate outcome of this matter will have a material adverse impact on Exelon’s or Generation’s results of operations, cash flows or financial position.

In a companion order also issued on September 19, 2008, FERC directed PJM and its stakeholders to evaluate whether prospective changes should be made to RPM and if a consensus is reached, file such a consensus with FERC in time to be in effect for the May 2009 RPM Auction. PJM filed a report with FERC on December 12, 2008 summarizing the discussions and explaining that a consensus was not reached. PJM also filed its own proposal with FERC on December 12, 2008. On March 26, 2009, FERC issued an order accepting in part and rejecting in part PJM’s December 12 filing, as amended by an Offer of Settlement filed by PJM and some members of PJM in response to the December 12 filing. A number of parties filed for rehearing and/or clarification of the March 26, 2009 Order. Any order may then be subject to review in the United States Court of Appeals.

License Renewals (Exelon and Generation). In July 2005, Generation applied for license renewal for Oyster Creek on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. The application was challenged by various citizen groups and the New Jersey

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Department of Environmental Protection (NJDEP). The contentions raised by these groups were reviewed and rejected by NRC’s Atomic Safety Licensing Board. In January 2008, the citizens group appealed the rejection of its contention to the NRC Commissioners. On April 1, 2009, the NRC Commissioners denied the appeal. The NJDEP appealed to the Third Circuit Court of Appeals one of its rejected contentions asserting that the NRC must consider terrorism risks as part of the re-licensing proceeding. On March 31, 2009, the Third Circuit denied that appeal. The NJDEP did not file further appeals and the time for filing such appeals has passed. On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek that expires in April 2029. On May 29, 2009, a coalition of six community groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the Third Circuit Court of Appeals. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.

On January 8, 2008, AmerGen submitted an application to the NRC to extend the operating license of TMI Unit 1 for an additional 20 years from the expiration of its current license to April 2034. The NRC is expected to spend up to 30 months to review the application before making a decision. To date, there have been no legal challenges to the application, and the time for filing objections has expired. Generation currently expects approval from the NRC in 2010.

4. Property Plant and Equipment (Exelon and Generation)

Long-Lived Asset Impairments (Exelon and Generation)

Generation evaluated its Texas plants, comprised of the Handley, Mountain Creek and LaPorte generating stations, for potential impairment as of December 31, 2008, pursuant to SFAS No. 144, and concluded that there was no impairment. Generation’s impairment test as of December 31, 2008 indicated that the plants’ estimated undiscounted future cash flows exceeded the carrying values of the plants and, therefore, an impairment did not exist. Due to the continued decline in forward energy prices in the first quarter of 2009, Generation again evaluated its Texas plants for recoverability as of March 31, 2009.

As the estimated undiscounted future cash flows and fair value of the Handley and Mountain Creek stations were less than the stations’ carrying values, the stations were determined to be impaired at March 31, 2009. LaPorte station was determined not to be impaired. Accordingly, the Handley and Mountain Creek stations were written down to fair value, and an impairment charge of $223 million was recorded in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations in the first quarter of 2009. The fair value of the stations was determined based upon the provisions of SFAS No. 157 and considered the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches in determining fair value. The actual proceeds that may be obtained from selling the plants would be dependent on the market conditions that exist at the time of any sale, terms and conditions of the sale agreement, and the actual combination of assets and liabilities transferred. These factors would impact the recognition of any potential gain or loss on sale.

During the second quarter of 2009, Generation assessed whether there had been any triggering events requiring an impairment assessment for any of its generating stations. Based on this analysis, it was determined that Generation did not have any triggering events requiring impairment assessments for any of its generating stations during the three months ended June 30, 2009.

See Note 6 — Fair Value of Assets and Liabilities for additional disclosures.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5. Intangible Assets (Exelon, Generation, ComEd and PECO)

Goodwill (Exelon and ComEd). As of June 30, 2009 and December 31, 2008, Exelon and ComEd had goodwill of approximately $2.6 billion. Under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” 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 or change in business conditions. Exelon and ComEd perform their annual goodwill impairment assessment in the fourth quarter of each year.

Because of the continued uncertainty in the financial markets and overall economic conditions, during the first and second quarters of 2009, ComEd reviewed the significant assumptions included in its goodwill impairment analysis to determine if it was more likely than not that ComEd’s fair value was less than its carrying value. The analyses focused on management’s current expectations of future cash flows, as well as current market conditions that impact various economic indicators that are utilized in assessing ComEd’s fair value. Based on these analyses, it was determined that ComEd did not have any triggering events requiring ComEd to perform a goodwill assessment during the six months ended June 30, 2009.

City of Chicago Settlements (Exelon and ComEd). Exelon’s and ComEd’s other intangible assets, included in deferred debits and other assets on the Consolidated Balance Sheets, include the following payments associated with the City of Chicago settlements as of June 30, 2009 and December 31, 2008:


June 30, 2009	Gross		Accumulated Amortization			Net		Estimated amortization expense
June 30, 2009	Gross		Accumulated Amortization			Net		Remainder of 2009		2010		2011		2012		2013
Chicago settlement – 1999 agreement(a)	$	100	$	(60	)	$	40	$	1	$	3	$	3	$	3	$	3
Chicago settlement – 2003 agreement(b)		62		(22	)		40		3		4		4		4		4

Total intangible assets	$	162	$	(82	)	$	80	$	4	$	7	$	7	$	7	$	7


December 31, 2008	Gross		Accumulated Amortization			Net		Estimated amortization expense
December 31, 2008	Gross		Accumulated Amortization			Net		2009		2010		2011		2012		2013
Chicago settlement – 1999 agreement(a)	$	100	$	(58	)	$	42	$	3	$	3	$	3	$	3	$	3
Chicago settlement – 2003 agreement(b)		62		(21	)		41		4		4		4		4		4

Total intangible assets	$	162	$	(79	)	$	83	$	7	$	7	$	7	$	7	$	7

(a)

In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments of $25 million to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

(b)

In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020.

Pursuant to the agreement discussed above, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under its 1999 fossil sale agreement with ComEd to build the generation facility

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.

Exelon’s and ComEd’s amortization expense related to intangible assets was $1 million for the three months ended June 30, 2009 and 2008 and $3 million for the six months ended June 30, 2009 and 2008.

RECs and AECs (Exelon, Generation and PECO). Exelon’s, Generation’s, and PECO’s other intangible assets, included in other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon and Generation) and AECs (PECO). As of June 30, 2009 and December 31, 2008, the balances of RECs and AECs for the Registrants were not significant. See Note 3- Regulatory Issues for additional information on RECs and AECs.

6. Fair Value of Assets and Liabilities (Exelon, Generation, ComEd and PECO)

Fair Value of Financial Liabilities Recorded at the Carrying Amount

Exelon

The carrying amounts and fair values of Exelon’s long-term debt, spent nuclear fuel obligation, and preferred securities of subsidiary as of June 30, 2009 and December 31, 2008 were as follows:


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	11,653	$	11,748	$	11,426	$	10,803
Long-term debt to PETT (including amounts due within one year)		794		832		1,124		1,193
Long-term debt to other financing trusts		390		253		390		200
Spent nuclear fuel obligation		1,016		758		1,015		544
Preferred securities of subsidiary		87		61		87		63

Generation

The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligation as of June 30, 2009 and December 31, 2008 were as follows:


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,513	$	2,574	$	2,514	$	2,402
Spent nuclear fuel obligation		1,016		758		1,015		544

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of June 30, 2009 and December 31, 2008 were as follows:


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	4,709	$	4,812	$	4,726	$	4,510
Long-term debt to financing trust		206		131		206		100

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of June 30, 2009 and December 31, 2008 were as follows:


	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,221	$	2,290	$	1,971	$	1,954
Long-term debt to PETT (including amounts due within one year)		794		832		1,124		1,193
Long-term debt to other financing trusts		184		121		184		100
Preferred securities		87		61		87		63

Recurring Fair Value Measurements

To increase consistency and comparability in fair value measurements, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities, exchange-based derivatives, mutual funds and money market funds.

•

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, commingled investment funds with observable market data and fair value hedges.

•

Level 3 — unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded non-exchange-based derivatives and commingled investment funds with unobservable market data and subject to purchase and sale restrictions.

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Exelon

The following table presents assets and liabilities measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2009 and December 31, 2008:


As of June 30, 2009 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	1,768	$	—		$	—		$	1,768	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		3		41			—			44
Equity securities		1,221		—			—			1,221	(b)
Commingled funds		—		110			1,679			1,789	(c)
Debt securities issued by the U.S. Treasury and other U.S government corporations and agencies		375		132			—			507
Debt securities issued by states of the United States and political subdivisions of the states		—		419			—			419
Corporate debt securities		—		692			—			692
Federal agency mortgage-backed securities		—		1,125			—			1,125
Commercial mortgage-backed securities (non-agency)		—		82			—			82
Residential mortgage-backed securities (non-agency)		—		8			—			8
Other debt obligations		—		87			—			87

Nuclear decommissioning trust fund investments subtotal		1,599		2,696			1,679			5,974	(d)

Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds		45		—			—			45	(e)

Rabbi trust investment subtotal		47		—			—			47	(f)

Mark-to-market derivative net assets		—		910			12			922	(g)(h)

Total assets		3,414		3,606			1,691			8,711

Liabilities
Deferred compensation		—		(76	)		—			(76	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(76	)		(2	)		(78	)

Total net assets	$	3,414	$	3,530		$	1,689		$	8,633

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	1,228	$	—		$	—		$	1,228	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—			13
Equity securities		903		—			—			903	(b)
Commingled funds		—		94			1,220			1,314	(c)
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		419		91			—			510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—			414
Corporate debt securities		—		764			—			764
Federal agency mortgage-backed securities		6		1,495			—			1,501
Commercial mortgage-backed securities (non-agency)		—		111			—			111
Other debt obligations		—		107			—			107

Nuclear decommissioning trust fund investments subtotal		1,341		3,076			1,220			5,637	(d)

Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds		43		—			—			43	(e)(f)

Rabbi trust investment subtotal		45		—			—			45	(f)

Mark-to-market derivative net assets		12		561			106			679	(g)(h)

Total assets		2,626		3,637			1,326			7,589
Liabilities
Deferred compensation		—		(85	)		—			(85	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(85	)		(2	)		(87	)

Total net assets	$	2,626	$	3,552		$	1,324		$	7,502

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s nuclear decommissioning trust funds hold equity portfolios whose performance is benchmarked against the Standard and Poor’s (S&P) 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index.

(c)

Generation’s nuclear decommissioning trust funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to track the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

(d)	Excludes net liabilities of $124 million and $137 million consisting of payables related to pending securities purchases net of cash, interest receivables and receivables related to pending securities sales at June 30, 2009 and December 31, 2008, respectively.

(e)	The mutual funds held by the Rabbi trusts invest in large cap equity securities and municipal debt securities. As of June 30, 2009, Exelon and ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(f)	Excludes $20 million and $19 million of the cash surrender value of life insurance investments at June 30, 2009 and December 31, 2008, respectively.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(g)

Includes both current and noncurrent mark-to-market derivative assets and interest rate swaps, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $285 million and $752 million at June 30, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(h)

Includes collateral postings received from and paid to counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $7 million and $993 million that are netted against Level 1 and Level 2 mark-to-market derivative net assets, respectively, as of June 30, 2009. Collateral received from counterparties, net of collateral paid to counterparties, totaled $11 million, $741 million and $1 million that are netted against Level 1, Level 2, and Level 3 mark-to-market derivative net assets, respectively, as of December 31, 2008.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2009 and 2008:


Three Months Ended June 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds		Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of March 31, 2009	$	1,371	$	48		$	(2	)	$	1,417
Total realized / unrealized gains (losses)
Included in net income		98		(33	)(a)		—			65
Included in other comprehensive income		—		(2	)(b)		—			(2	)
Included in regulatory assets (liabilities)		183		(1	)		—			182
Purchases, sales and issuances, net		27		—			—			27
Transfers into or out of Level 3		—		—			—			—

Balance as of June 30, 2009	$	1,679	$	12		$	(2	)	$	1,689

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009	$	97	$	(21	)	$	—		$	76

(a)	Includes the reclassification of $12 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $85 million of changes in the fair value and $60 million of realized losses due to settlements during the quarter of Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds		Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2008	$	1,220	$	106		$	(2	)	$	1,324
Total realized / unrealized gains (losses)
Included in net income		41		(101	)(a)		—			(60	)
Included in other comprehensive income		—		10	(b)		—			10
Included in regulatory assets (liabilities)		84		(1	)		—			83
Purchases, sales and issuances, net		334		—			—			334
Transfers into or out of Level 3		—		(2	)		—			(2	)

Balance as of June 30, 2009	$	1,679	$	12		$	(2	)	$	1,689

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009	$	40	$	(71	)	$	—		$	(31	)

(a)	Includes the reclassification of $30 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $667 million of changes in the fair value and $86 million of realized losses due to settlements during 2009 of Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended June 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of March 31, 2008	$	1,877		$	105		$	(1	)	$	1,981
Total realized / unrealized (losses) gains
Included in net income		(20	)		90	(a)		—			70
Included in other comprehensive income		—			(28	)(b)		—			(28	)
Included in regulatory liabilities		(37	)		—			—			(37	)
Purchases, sales and issuances, net		28			—			—			28
Transfers in or out of Level 3		—			—			—			—

Balance as of June 30, 2008	$	1,848		$	167		$	(1	)	$	2,014

The amount of total (losses) gains included in net income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of June 30, 2008	$	(20	)	$	121		$	—		$	101

(a)	Includes the reclassification of $31 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $226 million of changes in the fair value and $6 million of realized losses due to settlements during the second quarter of 2008 of Generation’s financial swap contract with ComEd since, at Exelon, the fair value balances are eliminated upon consolidation.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	2,019		$	52		$	(1	)	$	2,070
Total realized / unrealized (losses) gains
Included in net income		(95	)		146	(a)		—			51
Included in other comprehensive income		—			(31	)(b)		—			(31	)
Included in regulatory liabilities		(158	)		—			—			(158	)
Purchases, sales and issuances, net		82			—			—			82
Transfers into or out of Level 3		—			—			—			—

Balance as of June 30, 2008	$	1,848		$	167		$	(1	)	$	2,014

The amount of total (losses) gains included in net income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of June 30, 2008	$	(85	)	$	187		$	—		$	102

(a)	Includes the reclassification of $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $324 million of changes in the fair value and $6 million of realized losses due to settlements during 2008 of Generation’s financial swap contract with ComEd since, at Exelon, the fair value balances are eliminated upon consolidation.

The following table presents total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2009 and 2008:


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total (losses) gains included in net income for the three months ended June 30, 2009	$	(21	)	$	(10	)	$	(2	)	$	98
Total (losses) gains included in net income for the six months ended June 30, 2009	$	(42	)	$	(6	)	$	(53	)	$	41
Change in the unrealized (losses) gains relating to assets and liabilities held as of June 30, 2009 for the three months ended June 30, 2009	$	—		$	(9	)	$	(12	)	$	97
Change in the unrealized (losses) gains relating to assets and liabilities held as of June 30, 2009 for the six months ended June 30, 2009	$	—		$	(7	)	$	(64	)	$	40

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(In millions)	Operating Revenue		Purchased Power			Fuel		Other, net
Total gains (losses) included in net income for the three months ended June 30, 2008	$	72	$	(37	)	$	55	$	(20	)
Total gains (losses) included in net income for the six months ended June 30, 2008	$	84	$	(67	)	$	129	$	(95	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2008 for the three months ended June 30, 2008	$	83	$	(41	)	$	79	$	(20	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2008 for the six months ended June 30, 2008	$	106	$	(70	)	$	151	$	(85	)

Generation

The following table presents assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2009 and December 31, 2008:


As of June 30, 2009 (In millions)	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	1,506	$	—		$	—	$	1,506	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		3		41			—		44
Equity securities		1,221		—			—		1,221	(b)
Commingled funds		—		110			1,679		1,789	(c)
Debt securities issued by the U.S. Treasury and other U.S government corporations and agencies		375		132			—		507
Debt securities issued by states of the United States and political subdivisions of the states		—		419			—		419
Corporate debt securities		—		692			—		692
Federal agency mortgage-backed securities		—		1,125			—		1,125
Commercial mortgage-backed securities (non-agency)		—		82			—		82
Residential mortgage-backed securities (non-agency)		—		8			—		8
Other debt obligations		—		87			—		87

Nuclear decommissioning trust fund investments subtotal		1,599		2,696			1,679		5,974	(d)

Rabbi trust investments-mutual funds		4		—			—		4	(e)(f)
Mark-to-market derivative net assets		—		899			1,051		1,950	(g)(h)

Total assets		3,109		3,595			2,730		9,434

Liabilities
Deferred compensation obligation		—		(21	)		—		(21	)

Total liabilities		—		(21	)		—		(21	)

Total net assets	$	3,109	$	3,574		$	2,730	$	9,413

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	1,103	$	—		$	—	$	1,103	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—		13
Equity securities		903		—			—		903	(b)
Commingled funds		—		94			1,220		1,314	(c)
Debt securities issued by the U.S. Treasury and other U.S government corporations and agencies		419		91			—		510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—		414
Corporate debt securities		—		764			—		764
Federal agency mortgage-backed securities		6		1,495			—		1,501
Commercial mortgage-backed securities (non-agency)		—		111			—		111
Other debt obligations		—		107			—		107

Nuclear decommissioning trust fund investments subtotal		1,341		3,076			1,220		5,637	(d)

Rabbi trust investments-mutual funds		—		4			—		4	(e)(f)
Mark-to-market derivative net assets		12		544			562		1,118	(g)(h)

Total assets		2,456		3,624			1,782		7,862

Liabilities
Deferred compensation obligation		—		(25	)		—		(25	)

Total liabilities		—		(25	)		—		(25	)

Total net assets	$	2,456	$	3,599		$	1,782	$	7,837

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s nuclear decommissioning trust funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International EAFE Index.

(c)

(d)	Excludes net liabilities of $124 million and $137 million consisting of payables related to pending securities purchases net of cash, interest receivables and receivables related to pending securities sales at June 30, 2009 and December 31, 2008, respectively.

(e)	The mutual funds held by the Rabbi trusts that are invested in common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(f)	Excludes $6 million and $6 million of the cash surrender value of life insurance investments at June 30, 2009 and December 31, 2008, respectively.

(g)

Includes both current and noncurrent mark-to-market derivative assets and interest rate swaps, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance includes current and noncurrent assets for Generation and current and non-current liability for ComEd of $285 million and $752 million at June 30, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(h)

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2009 and 2008:


Three Months Ended June 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds		Mark-to-Market Derivatives			Total
Balance as of March 31, 2009	$	1,371	$	1,230		$	2,601
Total unrealized / realized gains (losses)
Included in net income		98		(33	)(a)		65
Included in other comprehensive income		—		(146	)(b)		(146	)
Included in noncurrent payables to affiliates		183		—			183
Purchases, sales, issuances and settlements, net		27		—			27
Transfers into or out of Level 3		—		—			—

Balance as of June 30, 2009	$	1,679	$	1,051		$	2,730

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009	$	97	$	(21	)	$	76

(a)	Includes the reclassification of $12 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $85 million of changes in the fair value and $60 million of realized losses due to settlements during the quarter of Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Six Months Ended June 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds		Mark-to-Market Derivatives			Total
Balance as of December 31, 2008	$	1,220	$	562		$	1,782
Total unrealized / realized gains (losses)
Included in net income		41		(101	)(a)		(60	)
Included in other comprehensive income		—		592	(b)		592
Included in noncurrent payables to affiliates		84		—			84
Purchases, sales, issuances and settlements, net		334		—			334
Transfers into or out of Level 3		—		(2	)		(2	)

Balance as of June 30, 2009	$	1,679	$	1,051		$	2,730

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009	$	40	$	(71	)	$	(31	)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(a)	Includes the reclassification of $30 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $667 million of changes in the fair value and $86 million of realized losses due to settlements during 2009 of Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended June 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds			Mark-to-Market Derivatives			Total
Balance as of March 31, 2008	$	1,877		$	(448	)	$	1,429
Total unrealized / realized (losses) gains
Included in net income		(20	)		90	(a)		70
Included in other comprehensive income		—			(249	)(b)		(249	)
Included in noncurrent payables to affiliates		(37	)		—			(37	)
Purchases, sales, issuances and settlements, net		28			—			28
Transfers in or out of Level 3		—			—			—

Balance as of June 30, 2008	$	1,848		$	(607	)	$	1,241

The amount of total (losses) gains included in net income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of June 30, 2008	$	(20	)	$	121		$	101

(a)	Includes the reclassification of $31 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $226 million of changes in the fair value and $6 million of realized losses due to settlements during the second quarter of 2008 of Generation’s financial swap contract with ComEd which, at Exelon, are eliminated upon consolidation.


Six Months Ended June 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments – Commingled Funds			Mark-to-Market Derivatives			Total
Balance as of January 1, 2008	$	2,019		$	(403	)	$	1,616
Total unrealized / realized (losses) gains
Included in net income		(95	)		146	(a)		51
Included in other comprehensive income		—			(350	)(b)		(350	)
Included in noncurrent payables to affiliates		(158	)		—			(158	)
Purchases, sales, issuances and settlements, net		82			—			82
Transfers in or out of Level 3		—			—			—

Balance as of June 30, 2008	$	1,848		$	(607	)	$	1,241

The amount of total (losses) gains included in net income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of June 30, 2008	$	(85	)	$	187		$	102

(a)	Includes the reclassification of $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(b)	Includes $324 million of changes in the fair value and $6 million of realized losses due to settlements during 2008 of Generation’s financial swap contract with ComEd which, at Exelon, are eliminated upon consolidation.


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total (losses) gains included in net income for the three months ended June 30, 2009.	$	(21	)	$	(10	)	$	(2	)	$	98
Total (losses) gains included in net income for the six months ended June 30, 2009.	$	(42	)	$	(6	)	$	(53	)	$	41
Change in the unrealized (losses) gains relating to assets and liabilities held as of June 30, 2009 during the three months ended June 30, 2009	$	—		$	(9	)	$	(12	)	$	97
Change in the unrealized (losses) gains relating to assets and liabilities held as of June 30, 2009 during the six months ended June 30, 2009	$	—		$	(7	)	$	(64	)	$	40


(In millions)	Operating Revenue		Purchased Power			Fuel		Other, net
Total gains (losses) included in net income for the three months ended June 30, 2008.	$	72	$	(37	)	$	55	$	(20	)
Total gains (losses) included in net income for the six months ended June 30, 2008.	$	84	$	(67	)	$	129	$	(95	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2008 during the three months ended June 30, 2008	$	83	$	(41	)	$	79	$	(20	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2008 during the six months ended June 30, 2008	$	106	$	(70	)	$	151	$	(85	)

ComEd

The following table presents assets measured and recorded at fair value on ComEd’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2009 and December 31, 2008:


As of June 30, 2009 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	27	$	—		$	—		$	27	(a)
Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds		34		—			—			34	(b)
Rabbi trust investment subtotal		36		—			—			36

Total assets		63		—			—			63

Liabilities
Deferred compensation obligation		—		(6	)		—			(6	)
Mark-to-market derivative liabilities		—		—			(1,037	)		(1,037	)(c)

Total liabilities		—		(6	)		(1,037	)		(1,043	)

Total net assets (liabilities)	$	63	$	(6	)	$	(1,037	)	$	(980	)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	16	$	—		$	—		$	16	(a)
Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds		32		—			—			32	(b)
Rabbi trust investment subtotal		34		—			—			34

Total assets		50		—			—			50

Liabilities
Deferred compensation obligation		—		(7	)		—			(7	)
Mark-to-market derivative liabilities		—		—			(456	)		(456	)(c)

Total liabilities		—		(7	)		(456	)		(463	)

Total net assets (liabilities)	$	50	$	(7	)	$	(456	)	$	(413	)

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)

The mutual funds held by the Rabbi trusts invest in stocks in the Russell 1000 index and municipal securities that are primarily rated as investment grade. As of June 30, 2009, ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(c)

The Level 3 balance is comprised of the current and noncurrent liability of $285 million and $752 million at June 30, 2009, respectively, and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of ComEd’s financial swap contract with Generation which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

The following table presents the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the three and six months ended June 30, 2009 and 2008:


Three Months Ended June 30, 2009 (In millions)	Mark-to-Market Derivatives
Balance as of March 31, 2009	$	(1,182	)
Total unrealized / realized gains
Included in regulatory assets		145

Balance as of June 30, 2009	$	(1,037	)


Six Months Ended June 30, 2009 (In millions)	Mark-to-Market Derivatives
Balance as of December 31, 2008	$	(456	)
Total unrealized / realized losses
Included in regulatory assets		(581	)

Balance as of June 30, 2009	$	(1,037	)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the three and six months ended June 30, 2009, ComEd had realized changes in fair value of $60 million and $86 million, respectively, which were recorded as additional purchased power expense, for the Level 3 mark-to-market derivative asset measured at fair value on a recurring basis related to ComEd’s financial swap contract with Generation, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended June 30, 2008 (In millions)	Mark-to-market derivatives
Balance as of March 31, 2008	$	554
Total realized / unrealized gains
Included in regulatory liabilities		220

Balance as of June 30, 2008	$	774


Six Months Ended June 30, 2008 (In millions)	Mark-to-market derivatives
Balance as of January 1, 2008	$	456
Total realized / unrealized gains
Included in regulatory liabilities		318

Balance as of June 30, 2008	$	774

During the three and six months ended June 30, 2008, ComEd had realized changes in fair value of $6 million, which were recorded as a reduction to purchased power expense, for the Level 3 mark-to-market derivative asset measured at fair value on a recurring basis related to ComEd’s financial swap contract with Generation, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

PECO

The following table presents assets and liabilities measured and recorded at fair value on PECO’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2009 and December 31, 2008:


As of June 30, 2009 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	184	$	—		$	—		$	184	(a)
Rabbi trust investments-mutual funds		6		—			—			6	(b)(c)
Total assets		190		—			—			190
Liabilities
Deferred compensation obligation		—		(25	)		—			(25	)
Mark-to-market derivative liabilities		—		—			(2	)		(2	)(d)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(25	)		(4	)		(29	)

Total net assets (liabilities)	$	190	$	(25	)	$	(4	)	$	161

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	26	$	—		$	—		$	26	(a)
Rabbi trust investments		6		—			—			6	(c)(b)

Total assets		32		—			—			32

Liabilities
Deferred compensation obligation		—		(28	)		—			(28	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(28	)		(2	)		(30	)

Total net assets (liabilities)	$	32	$	(28	)	$	(2	)	$	2

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	The mutual funds held by the Rabbi trusts invest in the common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)	Excludes $10 million of the cash surrender value of life insurance investments at June 30, 2009 and December 31, 2008.

(d)	The Level 3 balance represents a noncurrent liability of $2 million at June 30, 2009 related to the fair value of PECO’s block contracts, which is included in other deferred credits and other liabilities on PECO’s Consolidated Balance Sheets.

The following table presents the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the three and six months ended June 30, 2009:


Three Months Ended June 30, 2009 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of March 31, 2009	$	—		$	(2	)	$	(2	)
Included in regulatory assets		(2	)		—			(2	)

Balance as of June 30, 2009	$	(2	)	$	(2	)	$	(4	)


Six Months Ended June 30, 2009 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2008	$	—		$	(2	)	$	(2	)
Included in regulatory assets		(2	)		—			(2	)

Balance as of June 30, 2009	$	(2	)	$	(2	)	$	(4	)

There was no activity related to the mark-to-market derivatives and servicing liability during the three and six months ended June 30, 2008.

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd and PECO). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

table are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations. The nuclear decommissioning trust funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies restrict the trust funds from holding alternative investments and limit the trust funds’ exposures to investments in highly illiquid markets.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. For fixed income securities, the trustees receive multiple prices from pricing services, which enable cross-provider validations by the trustees in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources.

Investments with maturities of three months or less when purchased, including certain short-term fixed income securities, are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ—Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges. In addition, U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. To draw parallels from the trading and quoting of fixed income securities with similar features, pricing services consider various characteristics including the issuer, vintage, purpose of loan, collateral attributes, prepayment speeds, interest rates and credit ratings in order to properly value these securities. Commingled funds, which are similar to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of short-term commingled funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. However, because these short-term commingled funds are only offered to a limited group of investors and, therefore, not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices, specifically the S&P 500, the Russell 3000 and the Morgan Stanley Capital International EAFE indices, by purchasing equity securities to replicate the capitalization and characteristics of the indices. The fair value of these commingled funds are based on net asset values per fund share (the unit of account), primarily derived from the quoted prices in active markets of the underlying equity securities. However, because the shares of these commingled funds are not publicly quoted, not traded in an

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See Note 12 — Asset Retirement Obligations for further discussion on the nuclear decommissioning trust fund investments.

Rabbi Trust Investments (Exelon, Generation, ComEd and PECO). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets. The fair values of the shares of the funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

The Registrants evaluate the securities held in their Rabbi trusts for other-than-temporary impairment by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During June 2009, ComEd concluded that certain investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of ComEd’s ability and intent to hold the investments until the recovery of their cost basis. This analysis resulted in an impairment charge of $7 million (pre-tax) recorded in other income and deductions associated with ComEd’s investments held in Rabbi trusts.

Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the -counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of non-exchange-based derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk. The impacts of credit and nonperformance risk were not material to the financial statements.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Exelon may utilize fixed-to-floating interest-rate swaps, which are typically designated as fair-value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. Exelon uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, counterparty credit risk and market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest-rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 8 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd and PECO). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy.

Servicing Liability (Exelon and PECO). PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable. A servicing liability was recorded for the agreement in accordance with SFAS No. 156. The servicing liability is included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the liability has been determined using internal estimates based on provisions in the agreement, which are categorized as Level 3 inputs in the fair value hierarchy. See Note 14 — Commitments and Contingencies for further discussion on the accounts receivable agreement.

Non-recurring Fair Value Measurements

Asset Impairment (Exelon and Generation)

As discussed in Note 4 — Property, Plant and Equipment, as of March 31, 2009, Generation tested its Texas plants for potential impairment pursuant to SFAS No. 144 and recognized an impairment charge of $223 million in the first quarter of 2009 to reduce the carrying value of the Handley and Mountain Creek stations to fair value.

The impairment charge recorded by Generation for the Handley and Mountain Creek stations incorporated the fair values of the plants using unobservable inputs falling within Level 3 of the fair value hierarchy. As prescribed by SFAS No. 157, Generation determined fair value considering multiple valuation techniques including the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches. The results were evaluated and weighted, considering the reasonableness of the range indicated by those results. Significant inputs used under the income approach included forecasted cash flows based on forecasted generation, forward prices of natural gas and electricity, and overall generation availability in the Electric Reliability Council of Texas (ERCOT), and discount rate assumptions. Significant inputs under the transaction approach included market multiples that were derived from comparable transactions for peaking plants in ERCOT and other market regions and discount rate assumptions.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Short-Term Borrowings

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper, Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool and ComEd meets its short-term liquidity requirements primarily through borrowings under its credit facility.

As of June 30, 2009, Exelon Corporate, Generation, ComEd and PECO had access to unsecured revolving credit facilities with aggregate bank commitments of $957 million, $4.8 billion, $952 million and $574 million, respectively. See Note 10 of Exelon’s 2008 Annual Report on Form 10-K for further information regarding the credit facilities. Generation also has additional letter of credit facilities used solely to enhance tax-exempt variable rate debt as discussed further below.

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at June 30, 2009 and December 31, 2008:


Commercial paper borrowings	June 30, 2009		December 31, 2008
Exelon Corporate	$	—	$	56
Generation	$	—	$	—
PECO	$	—	$	95

Credit facility borrowings
ComEd	$	45	$	60

Issuance of Long-Term Debt

During the six months ended June 30, 2009, the following long-term debt was issued:


Company	Type	Interest Rate		Maturity	Amount(a)
Generation	Pollution Control Notes	5.00	%	December 1, 2042	$	46
ComEd	First Mortgage Bonds(b)	Variable		March 1, 2020		50
ComEd	First Mortgage Bonds(b)	Variable		March 1, 2017		91
ComEd	First Mortgage Bonds(b)	Variable		May 1, 2021		50
PECO	First Mortgage Bonds	5.00	%	October 1, 2014		250

(a)	Excludes unamortized bond discounts.

(b)	Variable-rate tax-exempt bonds secured by First Mortgage Bonds, which were remarketed in May 2009 following an earlier repurchase.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Retirement of Long-Term Debt

During the six months ended June 30, 2009, the following long-term debt was retired:


Company	Type	Interest Rate		Maturity	Amount
Generation	Pollution Control Notes	Variable		December 1, 2042	$	46
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		1
ComEd	First Mortgage Bonds(a)	Variable		March 1, 2020		50
ComEd	First Mortgage Bonds(a)	Variable		March 1, 2017		91
ComEd	First Mortgage Bonds(a)	Variable		May 1, 2021		50
ComEd	First Mortgage Bonds	5.70	%	January 15, 2009		16
ComEd	Sinking fund debentures	4.625-4.75	%	Various		1
PECO	PETT Transition Bonds	7.65	%	September 1, 2009		319
PECO	PETT Transition Bonds	6.52	%	March 1, 2010		11

(a)	Variable-rate tax-exempt bonds secured by First Mortgage Bonds, which were repurchased in May 2009 and subsequently remarketed.

As noted above, Generation repurchased $46 million in unenhanced tax-exempt variable-rate debt on February 23, 2009 due to a failed remarketing. In June 2009, Generation refinanced the debt with $46 million in bonds at a term rate through May 2012 with a maturity of 2042.

During the second quarter of 2009, ComEd repurchased $191 million of its credit enhanced variable-rate tax-exempt debt. This debt was then remarketed with credit enhancement provided by letters of credit issued under ComEd’s unsecured revolving credit facility. The letters of credit expire shortly before the expiration of the credit facility in 2011.

Generation has letters of credit that will expire in the third quarter of 2009, which are used to credit enhance variable-rate long-term tax-exempt debt totaling $307 million, with maturities ranging from 2021 – 2034. Generation plans to remarket certain of these bonds as unenhanced with different interest rate terms and refinance the others as new unenhanced tax-exempt bonds. Generation also has letter of credit facilities that will expire in the second quarter of 2010, which are used to credit enhance variable-rate long-term tax-exempt debt totaling $213 million, with maturities ranging from 2016 – 2034.

Under the terms of Generation’s and ComEd’s variable-rate tax-exempt debt agreements, Generation or ComEd may be required to repurchase the debt before its stated maturity unless supported by sufficient letters of credit. If Generation or ComEd were required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds with an interest rate term not requiring letter of credit support. Generation and ComEd have classified amounts outstanding under these debt agreements as long-term based on management’s intent and ability to either renew or replace the letters of credit, or refinance the debt at reasonable terms on a long-term fixed-rate basis.

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

The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exposed to market fluctuations in the prices of electricity, coal, natural gas, and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical contracts as well as financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.

The Registrants account for derivative instruments in accordance with SFAS No. 133, which requires that derivative instruments be recognized as either assets or liabilities at fair value. Under the provisions of SFAS No. 133, economic hedges are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales exception. The Registrants have applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133, to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Under the provisions of SFAS No. 133, for economic hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated other comprehensive income (OCI) and later reclassified into earnings when the underlying transaction occurs. For economic hedges that do not qualify or are not designated as cash flow hedges, changes in the fair value of the derivative are recognized in earnings each period and are classified as other derivatives in the following tables. Non-derivative contracts for access to additional generation and for sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, natural gas, coal and emission allowances 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, natural gas, coal and emission allowances. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2009, the percentage of expected generation hedged was 95%—98%, 87%—90%, and 59%—62% for 2009, 2010 and 2011, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

ComEd has locked in a fixed price for a significant portion of its commodity price risk to Generation through the five-year financial swap contract that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 3 — Regulatory Issues, qualify for the normal purchases and normal sales scope exception to SFAS No. 133. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no markup, ComEd’s price risk related to power procurement is limited.

In order to fulfill a requirement of the Illinois Settlement, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to coincide with ComEd’s remaining auction contracts for energy. The remaining swap contract volumes are 2,000 MW for the period extending June 2009 through May 2010 and 3,000 MW from June 2010 through May 2013. The terms of the financial swap contract require Generation to pay the market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changes in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument and records the fair value of the swap on its balance sheet. However, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Issues for additional information regarding the Illinois Settlement. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

PECO has transferred substantially all of its commodity price risk related to its procurement of electricity to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under SFAS No. 133.

Following the expiration of the PPA, PECO will procure electric generation through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3 – Regulatory Issues. Based on Pennsylvania legislation and PECO’s DSP Program permitting PECO to recover its electricity procurement costs from retail customers with no markup, PECO’s price risk related to electricity procurement will be limited. PECO will lock in fixed prices for a significant portion of its commodity price risk following the expiration of the electric generation rate caps through full requirements fixed price contracts and block contracts. PECO’s full requirements fixed price contracts qualify and have been designated for the normal purchases and

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

normal sales scope exception to SFAS 133. PECO accounts for the block contracts as other derivatives with the change in fair value recorded as a regulatory asset or liability. As of June 30, 2009, PECO’s mark-to-market position related to its block contracts was not significant.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy deliverability requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply agreements that are derivatives qualify for the normal purchases and normal sales exception to SFAS No. 133. Additionally, in accordance with the 2008 PAPUC purchased gas cost clause (PGC) settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2008 PGC settlement, PECO is required to lock-in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 20% to 25% of planned gas purchases in support of projected firm sales. The hedging program for gas procurement has no direct impact on PECO’s financial position or results of operations as fuel costs are fully recovered from customers under the PGC.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. 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. The proprietary trading activities, which included volumes of 2,003 gigawatt hours (GWhs) and 4,334 GWhs for the three and six months ended June 30, 2009 and 1,784 GWhs and 3,646 GWhs for the three and six months ended June 30, 2008, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.

Interest Rate Risk (Exelon, Generation and ComEd)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to achieve a lower cost of capital. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, Generation’s, and ComEd’s pre-tax income for the three and six months ended June 30, 2009.

Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. The Registrants include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows for the six months ended June 30, 2009:


Income Statement Classification	Loss on Swaps	Gain on Borrowings
Interest expense	$(6)	$6

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At June 30, 2009 and December 31, 2008, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $11 million and $17 million, respectively. During the three and six months ended June 30, 2009 and 2008, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Cash Flow Hedges. At June 30, 2009 and December 31, 2008, the Registrants did not have any interest rate swaps designated as cash flow hedges outstanding.

Fair Value Measurement (Exelon, Generation and ComEd)

Under the provisions of SFAS No. 161, the fair value of derivative instruments are required to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the statement of financial position in accordance with FSP FIN 39-1. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that are designated as normal purchases and normal sales and other non derivative contracts that are accounted for under the accrual method of accounting.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of June 30, 2009:


Derivatives	Generation															ComEd			Other						Exelon
Derivatives	Cash-Flow Hedges(a)			Other Derivatives			Proprietary Trading			Collateral and Netting(b)			Subtotal(c)			IL Settlement Swap(a)			Other Derivatives			Intercompany Eliminations(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	928		$	1,532		$	401		$	(2,234	)	$	627		$	—		$	—		$	—		$	627
Mark-to-market derivative assets with affiliate (current assets)		285			—			—			—			285			—			—			(285	)		—
Mark-to-market derivative assets (noncurrent assets)		607			699			139			(793	)		652			—			11			—			663
Mark-to-market derivative assets with affiliate (noncurrent assets)		753			—			—			—			753			—			—			(753	)		—

Total mark-to-market derivative assets	$	2,573		$	2,231		$	540		$	(3,027	)	$	2,317		$	—		$	11		$	(1,038	)	$	1,290

Mark-to-market derivative liabilities (current liabilities)	$	(20	)	$	(1,485	)	$	(351	)	$	1,562		$	(294	)	$	—		$	—		$	—		$	(294	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(285	)		—			285			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(34	)		(384	)		(120	)		465			(73	)		—			(1	)		—			(74	)
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)		—			—			—			—			—			(752	)		(1	)		753			—

Total mark-to-market derivative liabilities		(54	)		(1,869	)		(471	)		2,027			(367	)		(1,037	)		(2	)		1,038			(368	)

Total mark-to-market derivative net assets (liabilities)	$	2,519		$	362		$	69		$	(1,000	)	$	1,950		$	(1,037	)	$	9		$	—		$	922

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $285 million and $752 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral in accordance with FSP FIN 39-1.

(c)

In accordance with FSP FIN 39-1, current and noncurrent assets are shown net of collateral of $247 million and $280 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $425 million and $48 million, respectively. The total cash collateral received net of cash collateral posted was $1,000 million at June 30, 2009.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2008:


Derivatives	Generation															ComEd			Other					Exelon
Derivatives	Cash-Flow Hedges(a)			Other Derivatives			Proprietary Trading			Collateral and Netting(b)			Subtotal(c)			IL Settlement Swap(a)			Other Derivatives		Intercompany Eliminations(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	610		$	1,168		$	375		$	(1,743	)	$	410		$	—		$	—	$	—		$	410
Mark-to-market derivative assets with affiliate (current assets)		111			—			—			—			111			—			—		(111	)		—
Mark-to-market derivative assets (noncurrent assets)		437			552			124			(623	)		490			—			17		—			507
Mark-to-market derivative assets with affiliate (noncurrent assets)		345			—			—			—			345			—			—		(345	)		—

Total mark-to-market derivative assets	$	1,503		$	1,720		$	499		$	(2,366	)	$	1,356		$	—		$	17	$	(456	)	$	917

Mark-to-market derivative liabilities (current liabilities)	$	(47	)	$	(1,167	)	$	(291	)	$	1,291		$	(214	)	$	—		$	—	$	—		$	(214	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(111	)		—		111			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(19	)		(227	)		(100	)		322			(24	)		—			—		—			(24	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(345	)		—		345			—

Total mark-to-market derivative liabilities		(66	)		(1,394	)		(391	)		1,613			(238	)		(456	)		—		456			(238	)

Total mark-to-market derivative net assets (liabilities)	$	1,437		$	326		$	108		$	(753	)	$	1,118		$	(456	)	$	17	$	—		$	679

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $111 million and $345 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above. At Exelon, the fair value balances are eliminated upon consolidation.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral in accordance with FSP FIN 39-1.

(c)

In accordance with FSP FIN 39-1, current and noncurrent assets are shown net of collateral of $177 million and $252 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $274 million and $50 million, respectively. The total cash collateral received net of cash collateral posted was $753 million at December 31, 2008.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges (Exelon and Generation). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2009, Generation had net unrealized pre-tax gains on effective cash flow hedges of $2,511 million being deferred within accumulated OCI, including approximately $1,037 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2009, approximately $1,194 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $285 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges will occur during 2009 through 2011, and the ComEd financial swap contract during 2009 through 2013.

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward starting hedges, or it is no longer probable that the forecasted transaction will occur. For the three and six months ended June 30, 2009, there were no gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedges.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 2009 and 2008, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.


Three Months Ended June 30, 2009	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2009		$	1,814	(a)	$	1,110
Effective portion of changes in fair value			(42	)(b)		4
Reclassifications from accumulated OCI to net income	Operating Revenue		(262	)(c)		(226	)
Ineffective portion recognized in income	Purchased Power		2			2

Accumulated OCI derivative gain at June 30, 2009		$	1,512	(a)	$	890

(a)	Includes $624 million and $712 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2009 and March 31, 2009, respectively.

(b)	Includes $52 million loss, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2009.

(c)	Includes $36 million loss, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2009.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2009	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2008		$	855	(a)	$	585
Effective portion of changes in fair value			1,059	(b)		654
Reclassifications from accumulated OCI to net income	Operating Revenue		(407	)(c)		(354	)
Ineffective portion recognized in income	Purchased Power		5			5

Accumulated OCI derivative gain at June 30, 2009		$	1,512	(a)	$	890

(a)	Includes $624 million and $275 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2009 and December 31, 2008, respectively.

(b)	Includes $401 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2009.

(c)	Includes $52 million loss, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2009.


Three Months Ended June 30, 2008	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at March 31, 2008		$	(1,065	)(a)	$	(743	)
Effective portion of changes in fair value			(741	)(b)		(604	)
Reclassifications from accumulated OCI to net income	Operating Revenue		126	(c)		122
Ineffective portion recognized in income	Purchased Power		19			3

Accumulated OCI derivative loss at June 30, 2008		$	(1,661	)(a)	$	(1,222	)

(a)	Includes $436 million and $318 million of losses, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2008 and March 31, 2008, respectively.

(b)	Includes $121 million loss, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the three months ended June 30, 2008.

(c)	Includes $4 million gain, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd during the three months ended June 30, 2008.


Six Months Ended June 30, 2008	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2007		$	(548	)(a)	$	(270	)
Effective portion of changes in fair value			(1,346	)(b)		(1,150	)
Reclassifications from accumulated OCI to net income	Operating Revenue		183	(c)		179
Ineffective portion recognized in income	Purchased Power		50			19

Accumulated OCI derivative loss at June 30, 2008		$	(1,661	)(a)	$	(1,222	)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(a)	Includes $436 million and $275 million of losses, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2008 and December 31, 2007, respectively.

(b)	Includes $165 million loss, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the six months ended June 30, 2008.

(c)	Includes $4 million gain, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd during the six months ended June 30, 2008.

During the three and six months ended June 30, 2009, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $434 million pre-tax gain and a $674 million pre-tax gain, respectively, and a ($209) million and ($304) million pre-tax loss for the three and six months ended June 30, 2008, respectively. Given that the cash-flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. During the three and six months ended June 30, 2009, cash flow hedge ineffectiveness changed by $3 million and $8 million due primarily to the change in market prices during the period, of which none was related to Generation’s financial swap contract with ComEd. At June 30, 2009, cash flow hedge ineffectiveness resulted in an adjustment of $7 million to accumulated OCI on the balance sheet in order to reflect the effective portion of derivative gains or losses. During the three and six months ended June 30, 2008, cash-flow hedge ineffectiveness of $31 million and $81 million, respectively, was reclassified from accumulated OCI into results of operations, of which $26 million, and $51 million, respectively, was related to Generation’s financial swap contract with ComEd.

Exelon’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $373 million pre-tax gain and $587 million pre-tax gain for the three and six months ended June 30, 2009, respectively, and a ($203) million pre-tax loss and ($297) million pre-tax loss for the three and six months ended June 30, 2008. Cash flow hedge ineffectiveness impact to pre-tax earnings based on the reclassifications from accumulated OCI into earnings resulted in $3 million pre-tax and $8 million pre-tax for the three and six months ended June 30, 2009, respectively, and $5 million pre-tax and $30 million pre-tax for the three and six months ended June 30, 2008.

Other Derivatives (Exelon and Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three and six months ended June 30, 2009 and 2008, the following net pre-tax mark-to-market gains (losses) relating to changes in the fair values of certain purchase power and sale contracts pursuant to SFAS No. 133 were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and are included in Net fair value changes related to derivatives and nuclear decommissioning trust funds in Exelon’s and Generation’s Consolidated Statements of Cash Flows.


	Exelon and Generation
Three Months Ended June 30, 2009	Purchased Power			Fuel			Total
Unrealized mark-to-market losses	$	(114	)	$	(59	)	$	(173	)
Realized mark-to-market gains (losses)		(50	)		53			3

Total net mark-to-market losses	$	(164	)	$	(6	)	$	(170	)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Exelon and Generation
Six Months Ended June 30, 2009	Purchased Power			Fuel			Total
Unrealized mark-to-market gains (losses)	$	142		$	(102	)	$	40
Realized mark-to-market gains (losses)		(96	)		76			(20	)

Total net mark-to-market gains (losses)	$	46		$	(26	)	$	20


	Exelon and Generation
Three Months Ended June 30, 2008	Purchased Power			Fuel			Total
Unrealized mark-to-market gains (losses)	$	(49	)	$	168		$	119
Realized mark-to-market gains (losses)		33			(44	)		(11	)

Total net mark-to-market gains (losses)	$	(16	)	$	124		$	108


	Exelon and Generation
Six Months Ended June 30, 2008	Purchased Power		Fuel			Total
Unrealized mark-to-market gains	$	121	$	111		$	232
Realized mark-to-market gains (losses)		50		(61	)		(11	)

Total net mark-to-market gains	$	171	$	50		$	221

Proprietary Trading Activities (Exelon and Generation). For the three and six months ended June 30, 2009 and 2008, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in Net fair value changes related to derivatives and nuclear decommissioning trust funds in Exelon’s and Generation’s Consolidated Statements of Cash Flows.


	Location on Income Statement	Three Months Ended June 30,						Six Months Ended June 30,
	Location on Income Statement	2009			2008			2009			2008
Unrealized mark-to-market gains	Operating Revenue	$	3		$	81		$	3		$	103
Realized mark-to-market losses	Operating Revenue		(22	)		(12	)		(43	)		(23	)

Total net mark-to-market gains (losses)	Operating Revenue	$	(19	)	$	69		$	(40	)	$	80

Credit Risk (Exelon, Generation, ComEd and PECO)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2009. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through Regional Transmission Organizations (RTOs), Independent System Operators (ISOs) and New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $115 million and $181 million, respectively. See Note 17 — Related-Party Transactions for further information.


Rating as of June 30, 2009	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number Of Counterparties Greater than 10% of Net Exposure	Net Exposure Of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,585	$	540	$	1,045	1	$	113
Non-investment grade		7		6		1	—		—
No external ratings
Internally rated — investment grade		1		—		1	—		—
Internally rated — non-investment grade		32		6		26	—		—

Total	$	1,625	$	552	$	1,073	1	$	113


Net Credit Exposure by Type of Counterparty	As of June 30, 2009
Financial institutions	$	415
Investor-owned utilities, marketers and power producers		578
Coal		3
Other		77

Total	$	1,073

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spot market compared to the benchmark prices. The benchmark prices are the future prices of energy projected through the contract term and are set at the point of contract execution. If the price of energy in the spot market exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s credit exposure. As of June 30, 2009, ComEd’s credit exposure to suppliers was immaterial and did not exceed the unsecured levels allowed by contract.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Issues for further information.

PECO has a PPA with Generation under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010. Generation supplies electricity to PECO from its portfolio of generation assets, PPAs and other market sources at prices that are below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers. PECO could be negatively affected if Generation could not perform under the PPA. See Note 3 — Regulatory Issues for further information regarding the impact of regulatory matters on PECO’s procurement of electricity and gas.

PECO’s supplier master agreements that govern the terms of its DSP program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the current forward price curve for energy compared to the initial market price, the forward price of energy on the day a transaction is executed. If the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2009, PECO had no credit exposure to suppliers under its electric procurement contracts, as the initial market price was greater than market prices.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply agreements. As of June 30, 2009, PECO had no price exposure under its natural gas supply contracts as the fixed-contract obligation costs are greater than projected market prices.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that, if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Where applicable, this incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features, excluding transactions on NYMEX and ICE that are fully collateralized, that are in a liability position and are not fully collateralized as of June 30, 2009, was $1,722 million. Generation had the contractual right of offset of $1,532 million related to derivative instruments that are assets with the same counterparty under master netting

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreements, resulting in a net liability position of $190 million, which is net of $10 million of cash collateral posted in the normal course of business. If Generation had been downgraded to the investment grade rating of BBB- and Baa3 or lost its investment grade credit rating as of June 30, 2009, it would have been required to provide incremental collateral of approximately $60 million and $557 million, respectively, related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 14 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

Beginning in 2007, under the Illinois auction rules and the supplier forward contracts that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers. Generation entered into similar supplier forward contracts with Ameren, with one-sided collateral postings only from Generation. If market prices fall below ComEd’s or Ameren’s benchmark price levels, ComEd or Ameren are not required to post collateral; however, when market prices rise above benchmark price levels with ComEd or Ameren, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the five-year financial swap contract between Generation and ComEd, there are no immediate collateral provisions on either party. However, the swap contract also provides that: (1) if ComEd is downgraded below investment grade by Moody’s Investor Service (Moody’s) or Standard & Poor’s (S&P), or (2) if Generation is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by the applicable party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Beginning in June 2009, under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2009, there was no cash collateral or letters of credit posted between suppliers, including Generation, and ComEd, under any of the above-mentioned contracts. See Note 3 — Regulatory Issues for further information.

PECO has a PPA with Generation under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010. There are no collateral-related provisions included in the PPA between PECO and Generation.

PECO’s supplier master agreements that govern the terms of its DSP program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2009, PECO was not required to post collateral for any of these agreements. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2009, PECO could be required to post approximately $48 million of collateral to its counterparties.

Exelon’s interest-rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest-rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2009, Exelon’s interest-rate swap was in an asset position, with a fair value of $11 million.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

Exelon and Generation adopted the provisions of FSP FIN 39-1 on January 1, 2008. As a result of the adoption, Exelon and Generation record cash flow hedges and other derivative and proprietary trading activities in the balance sheet on a net basis and offset the fair value amounts recognized for energy-related derivatives with cash collateral paid to or received from counterparties under master netting arrangements.

As of June 30, 2009 and December 31, 2008, $3 million and $5 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.

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

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and Exelon Corporate employees. Prior to January 8, 2009, employees of Generation’s wholly owned subsidiary, AmerGen, participated in the separate AmerGen-sponsored defined benefit pension plan and postretirement benefit plan. Effective January 8, 2009, the AmerGen legal entity was dissolved and Exelon became the sponsor of all AmerGen pension and postretirement benefit plans. The unrecognized costs of the AmerGen plans in accumulated OCI of $20 million (after-tax) were reduced to zero and the corresponding amounts were recorded to the net liability position of the plans at Generation. The change in sponsorship did not have an impact on Exelon’s Consolidated Financial Statements.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2009, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2009. This valuation resulted in an increase to the pension obligations of $57 million and a decrease to other postretirement obligations of $144 million. Additionally, OCI decreased by approximately $28 million (after-tax). The impact to the Consolidated Statement of Operations and Comprehensive Income was not material.

The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, 2009 and 2008. The 2009 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.50%. The 2009 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 8.10%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.


	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2009			2008			2009			2008
Service cost	$	45		$	41		$	28		$	27
Interest cost		162			159			50			52
Expected return on assets		(194	)		(209	)		(23	)		(30	)
Amortization of:
Transition obligation		—			—			3			2
Prior service cost (benefit)		3			3			(14	)		(14	)
Actuarial loss		49			32			22			13

Net periodic benefit cost	$	65		$	26		$	66		$	50

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,
	2009			2008			2009			2008
Service cost	$	89		$	82		$	56		$	54
Interest cost		325			318			102			104
Expected return on assets		(388	)		(418	)		(47	)		(60	)
Amortization of:
Transition obligation		—			—			5			4
Prior service cost (benefit)		7			6			(28	)		(28	)
Actuarial loss		98			64			44			26
Settlements		—			6			—			—

Net periodic benefit cost	$	131		$	58		$	132		$	100

The following amounts were included in capital additions and operating and maintenance expense during the three and six months ended June 30, 2009 and 2008, for Generation’s, ComEd’s, PECO’s and Exelon Corporate’s allocated portion of the pension and postretirement benefit plans:


Pension and Postretirement Benefit Costs	Three Months Ended June 30,				Six Months Ended June 30,
Pension and Postretirement Benefit Costs	2009		2008		2009		2008
Generation	$	59	$	35	$	119	$	70
ComEd		48		25		96		50
PECO		12		8		24		16
Other(a)		12		8		24		22

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

Exelon expects to contribute approximately $245 million to the benefit plans in 2009, of which Generation, ComEd and PECO expect to contribute $115 million, $59 million and $40 million, respectively.

Plan Assets

The majority of the benefit plans participates in a securities lending program with the trustees of the plans’ investment trusts. The program authorizes the trustee of the particular trust to lend securities, which are assets of the plan, to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is invested in collateral funds comprised primarily of short-term investment vehicles. Collateral may not be sold or re-pledged by the trustees, however, the borrowers may sell or re-pledge the loaned securities. Exelon’s benefit plans bear the risk of loss with respect to unfavorable changes in the fair value of the invested cash collateral. Such losses may result from a decline in the fair value of specific investments or liquidity impairments resulting from current market conditions. Exelon, the trustees and the borrowers have the right to terminate the lending agreement at their

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

discretion, upon which borrowers would return securities to Exelon in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Exelon may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by the trusts, whether the result of declines in fair value or liquidity impairments, were not material during the period ended June 30, 2009 and the year ended December 31, 2008. Management continues to monitor the performance of the invested collateral and work closely with the trustees to limit any potential losses.

In the fourth quarter of 2008, Exelon decided to end its participation in the securities lending program. However, Exelon has chosen to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the absence of liquidity in the market. Currently, the weighted average maturity of the securities within the collateral funds is approximately 6 months. At December 31, 2008, Exelon had $269 million of loaned securities outstanding and held $274 million of related collateral under its lending agreements. At June 30, 2009, under its lending agreements, Exelon had $101 million of loaned securities outstanding and the fair value of related collateral held was $103 million, representing a decrease in loaned securities outstanding since December 31, 2008 of $168 million primarily due to the return of loaned securities. Of the balance of loaned securities outstanding at June 30, 2009 (in terms of value), approximately 60% is expected to be returned by the end of 2009, with the remainder expected to be returned primarily in 2010. A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trusts and the trustees in their capacity as security agents.

401(k) Savings Plan

The Registrants participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their income in accordance with specified guidelines. The Registrants match a percentage of the employee contributions up to certain limits. The following table presents, by registrant, the matching contributions to the savings plans during the three and six months ended June 30, 2009 and 2008:


Savings Plan Matching Contributions	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2009		2008		2009		2008
Exelon	$	18	$	17	$	36	$	33
Generation		9		8		18		16
ComEd		5		5		10		10
PECO		2		2		4		4

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

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

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On June 18, 2009, Exelon announced a restructured senior executive team and major spending cuts, including the elimination of approximately 500 positions. Exelon expects that approximately 400 corporate support positions, mostly located at corporate headquarters, and 100 management level positions at ComEd will be eliminated. Exelon and ComEd expect to complete most job reductions by August 31, 2009. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry especially in light of the commodity-driven nature of Generation’s markets, necessitating continued focus on cost management through enhanced efficiency and productivity.

Exelon recorded a pre-tax charge for salary continuance and health and welfare severance benefits of $40 million in June 2009 as a result of the planned job reductions. The final amount of the charge will ultimately depend on the specific employees severed.

The following tables present total severance benefits costs, recorded as operating and maintenance expense in relation to the announced job reductions, for the three and six months ended June 30, 2009:


Severance Benefits	Generation		ComEd		PECO		Other		Exelon
Expense recorded for the three and six months ended June 30, 2009(a)(b)	$	15	$	18	$	5	$	2	$	40

(a)	The amounts above include $8 million, $5 million and $3 million at Generation, ComEd and PECO, respectively, for amounts billed through intercompany allocations.

(b)	The severance benefits costs include $1 million of stock compensation expense collectively at Generation and ComEd for which the obligation is recorded in equity.

The following table presents the activity of severance obligations for the announced job reductions from January 1, 2009 through June 30, 2009, excluding obligations recorded in equity:


Severance Benefits Obligations	Generation		ComEd		PECO		Other		Exelon
Balance at January 1, 2009	$	—	$	—	$	—	$	—	$	—
Severance charges recorded		7		12		2		18		39
Cash payments		—		—		—		—		—

Balance at June 30, 2009	$	7	$	12	$	2	$	18	$	39

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

Exelon’s effective income tax rate from continuing operations for the three and six months ended June 30, 2009 was 39.5% and 35.1%, as compared to 35.9% and 33.7% for the three and six months ended June 30, 2008. The increase in the effective tax rate for the three and six months ended June 30, 2009 was primarily attributable to gains generated in Generation’s nuclear decommissioning trust funds that are taxed at a higher statutory rate than Generation’s remaining income from operations. The increase for the six months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a change in deferred state income taxes (see Long-Term State Tax Apportionment below), and an Illinois Supreme Court decision granting ITC to Exelon and treating electricity as tangible personal property. The increase for the three months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a change in deferred state income taxes.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Generation’s effective income tax rate from continuing operations for the three and six months ended June 30, 2009 was 41.0% and 35.7%, as compared to 37.0% and 34.9% for the three and six months ended June 30, 2008. Generation’s effective tax rate for the three and six months ended June 30, 2009 increased as a result of gains generated in the nuclear decommissioning trust funds that are taxed at a higher statutory rate than Generation’s remaining income from operations. The increase for the six months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a change in deferred state income taxes, and an Illinois Supreme Court decision granting ITC to Exelon and treating electricity as tangible personal property. The increase for the three months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a change in deferred state income taxes.

ComEd’s effective income tax rate for the three and six months ended June 30, 2009 was 38.6% and 32.9%, as compared to 37.5% and 38.2% for the three and six months ended June 30, 2008. For the three months ended June 30, 2009, the increase in the effective tax rate was primarily a result of increased income while permanent differences remained relatively constant. For the six months ended June 30, 2009, the decrease in effective tax rate was a result of a reduction in state income tax expense primarily driven by an Illinois Supreme Court decision granting ITC to Exelon.

PECO’s effective income tax rate for the three and six months ended June 30, 2009 was 30.4% and 29.3%, as compared to 30.1% and 30.8% for the three and six months ended June 30, 2008, respectively. The decrease in the effective tax rate for the six months ended June 30, 2009 was primarily caused by a decrease in state income tax expense due to higher deductible interest expense partially offset by the tax benefit recorded in 2008 related to a tax settlement with the IRS.

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd and PECO have $1.35 billion, $539 million, $440 million and $339 million, respectively, of unrecognized tax benefits as of June 30, 2009. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2008 except for those relating to the 1999 sale of fossil generating assets discussed below.

1999 Sale of Fossil Generating Assets (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the Internal Revenue Code (the Code). Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Act). The proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain was deferred over the lives of the replacement property under the involuntary conversion provisions. Approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the Code. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction. Specifically, the IRS has asserted that ComEd was not forced to sell the fossil generating plants and the sales

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

proceeds were therefore not received in connection with an involuntary conversion of certain ComEd property rights. Accordingly, the IRS has asserted that the gain on the sale of the assets was fully subject to tax. The IRS also asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a “sale-in, lease-out” (SILO), which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback does not qualify as a like-kind exchange such that the gain on the sale is fully subject to tax.

In addition to attempting to impose tax on the transactions, the IRS has asserted penalties of approximately $196 million for a substantial understatement of tax. Because Exelon believes it is unlikely that the penalty assertion will ultimately be sustained, Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty it would result in an after-tax charge of $196 million to Exelon’s and ComEd’s results of operations.

Exelon disagrees with the IRS disallowance of the deferral of gain and specifically with the characterization of its purchase and leaseback as a SILO. Exelon has been in discussions with the Appeals Division of the IRS (IRS Appeals) for several months in an attempt to reach a settlement on both the involuntary conversion and like-kind exchange, in a manner commensurate with Exelon’s and the IRS’ respective hazards of litigation with respect to each issue. During the second quarter of 2009, Exelon determined that a settlement with IRS Appeals is unlikely and that Exelon will be required to initiate litigation in order to resolve the issues.

Accordingly, Exelon has concluded that it has sufficient new information that a change in measurement under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48) is required. As a result of the required re-measurement of these two positions in the second quarter, Exelon recorded a $31 million (after-tax) interest benefit of which $40 million (after-tax) was recorded at ComEd. The difference in amounts recorded at Exelon and ComEd is due to the method of allocating interest to the Registrants.

Due to the fact that tax litigation often results in a negotiated settlement, Exelon believes that an eventual settlement on the involuntary conversion position remains a likely outcome. In accordance with FIN 48, Exelon and ComEd have established a liability for an unrecognized tax benefit consistent with their view as to a likely settlement. Exelon believes that, due to the length of the litigation process, it is unlikely that it will engage in further substantive settlement discussions regarding the involuntary conversion position within the next twelve months.

With regard to the like kind exchange transaction, Exelon does not currently believe it is possible to reach a negotiated settlement with either IRS Appeals or the Government’s lawyers prior to a trial. While Exelon has been and remains willing to settle the issue in a manner commensurate with its hazards of litigation, the IRS has indicated that it will only settle the issue in a manner consistent with published settlement guidelines for SILO transactions. Those guidelines require a nearly complete concession of the issue by Exelon. Exelon does not believe that its transaction is the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS reflects the strength of Exelon’s position. Accordingly, Exelon currently believes that it is likely that the issue will be fully litigated. Given that Exelon has determined that settlement is no longer a realistic outcome, it has assessed in accordance with accounting standards whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and has therefore eliminated any liability for unrecognized tax benefits in accordance with the requirements of FIN 48.

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A fully successful IRS challenge to Exelon’s and ComEd’s involuntary conversion position and like kind exchange transaction would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of June 30, 2009, Exelon’s and ComEd’s potential tax and interest that could become currently payable in the event of a successful IRS challenge could be as much as $1.1 billion. Any payments ultimately determined to be due to the IRS related to the involuntary conversion position and the like kind exchange transaction would be partially offset by the approximately $300 million refund due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the Simplified Service Cost Method. A favorable settlement of the tax position related to the competitive transition charges (discussed below) for the 1999-2001 years could also offset a portion of any tax liability due with respect to the final outcome on these positions. If the IRS were to prevail in litigation on both tax positions, Exelon’s and ComEd’s results of operations could be negatively impacted by as much as $300 million (after-tax) related to interest expense.

Illinois Replacement Investment Tax Credits (Exelon, Generation and ComEd)

On February 20, 2009, the Illinois Supreme Court ruled in Exelon’s favor in a case involving refund claims for Illinois investment tax credits. Consequently, Exelon recorded approximately $42 million (after-tax) of income in results of operations in the first quarter of 2009 to reflect the refund claims for investment tax credits and associated interest for the years 1995 – 2008; $35 million and $8 million were recorded at ComEd and Generation, respectively.

Responding to the Illinois Attorney General’s petition for rehearing, on July 15, 2009, the Illinois Supreme Court changed its opinion to indicate that it was to be applied only prospectively, beginning in 2009. As a result, Exelon is no longer entitled to the claimed refunds. Exelon is evaluating its options; however, unless the Supreme Court changes its position again, Exelon, Generation and ComEd will record a charge to third quarter results of operations to reverse the income previously recognized.

Competitive Transition Charges (Exelon, ComEd and PECO)

Exelon contends that the 1997 Illinois Act and the 1996 Pennsylvania Electricity Generation Customer Choice and Competition Act (the Pennsylvania Act) resulted in the taking of certain of ComEd’s and PECO’s assets used in their respective businesses of providing electricity services in their defined service areas. Exelon has filed refund claims with the IRS taking the position that competitive transition charges (CTCs) collected during ComEd’s and PECO’s transition periods represent compensation for that taking and, accordingly, are excludible from taxable income as proceeds from an involuntary conversion. If Exelon is successful in its claims, it will be required to reduce the tax basis of property acquired with the funds provided by the CTCs such that the benefits of the position are temporary in nature. The IRS has disallowed the refund claims for the 1999-2001 tax years and Exelon has protested the disallowance to IRS Appeals. The years 2002-2006 are currently under IRS audit and Exelon expects the claims for those years to be disallowed when filed.

Under the Illinois Act, ComEd was required to allow competitors the use of its distribution system resulting in the taking of ComEd’s assets and lost asset value (stranded costs). As compensation for the taking, ComEd was permitted to collect a portion of the stranded costs through the collection of CTCs from customers electing to purchase electricity from providers other than ComEd. ComEd collected approximately $1.2 billion in CTCs for the years 1999-2006.

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Similarly, under the Pennsylvania Act, PECO was required to allow others the use of its distribution system resulting in the taking of PECO’s assets and the stranded costs. Pennsylvania permitted PECO to collect CTCs as compensation for its stranded costs. The PAPUC determined the total amount of stranded costs that PECO was permitted to collect through the CTCs to be $5.26 billion. PECO has collected approximately $3.6 billion in CTCs for the years 2000-2008 and will continue the collection of CTCs through 2010.

ComEd and PECO have recognized tax benefits associated with the CTC refund claims and have accrued interest on this tax position consistent with the requirements of FIN 48. Exelon’s, ComEd’s, and PECO’s management believe that the issue has been appropriately recognized in accordance with FIN 48; however, the ultimate outcome of this matter could result in unfavorable or favorable impacts to the results of operations and financial positions as well as potential favorable impacts to cash flows, and such impacts could be material. Management has considered the progress of the ongoing appeal and determined that there are no new developments that lead to a re-measurement of the amounts recorded. Based on management’s expectations as to the length of the IRS appeal, it is reasonably possible that the unrecognized tax benefits related to this issue may significantly increase or decrease within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

Nuclear Decommissioning Liabilities (Exelon and Generation)

Generation filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. During 2008, Generation had several discussions with IRS Appeals but was unable to reach a satisfactory settlement. In November of 2008, Generation received a final determination from Appeals disallowing its refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. The Department of Justice has not yet filed its answer.

The trial judge assigned to the case has noted the availability of the Court’s Alternative Dispute Resolution (ADR) program as an alternative to a trial, but the parties have not yet met with the ADR judge. The ADR program is a non-binding process that utilizes a variety of techniques such as mediation, neutral evaluation, and non-binding arbitration that allow the parties to better understand their differences and their prospects for settlement. While it is unclear when the parties might meet with the ADR judge, the process could result in an expedited conclusion of the matter. As a result, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits will significantly decrease in the next twelve months.

Other Tax Matters

Illinois Senate Bill 1544 and Senate Bill 783 (Exelon)

In August 2007, Illinois enacted Senate Bill (SB) 1544, which became effective January 1, 2008. SB 1544 provided for new rules related to the sourcing of receipts from services for Illinois income tax purposes. The rules provide for sourcing receipts from services based upon where the benefit of the service was realized. In January 2008, Illinois enacted SB 783, which amended certain provisions of SB 1544, including the rules pursuant to which receipts from services should be sourced for Illinois income tax purposes. Pursuant to SB 783, receipts from services generally should be sourced based upon where the services are received. SB 783 also expressly provides that the Illinois Department of Revenue shall adopt rules prescribing where utility services are received. On December 26, 2008, the Illinois Department of Revenue proposed regulations prescribing where

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utility services are received. As discussed above on February 20, 2009, the Illinois Supreme Court ruled that electricity is tangible personal property and on July 15, 2009 dismissed the Attorney General’s petition for rehearing but modified its decision to apply only prospectively. Accordingly, with electricity being treated as tangible personal property rather than as a service beginning in 2009, the rules under SB 1544 and SB 783 will likely no longer be applicable absent a legislative change.

Long-Term State Tax Apportionment (Exelon and Generation)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon’s and Generation’s deferred state income taxes. On April 16, 2009, the PAPUC approved Exelon’s electricity procurement proposal that will have an impact on Exelon’s and Generation’s apportionment of income among the states. Accordingly, Exelon and Generation reevaluated the impacts to deferred state taxes in the second quarter of 2009. The effect of such evaluations resulted in the recording of a non-cash deferred state tax benefit in the amount of$34.7 million, net of taxes. Exelon and Generation have treated electricity as tangible personal property for this purpose which is consistent with the February and July 2009 Illinois Supreme Court decisions.

12. Asset Retirement Obligations and Spent Nuclear Fuel Storage (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations (ARO)

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. Generation will pay for its respective obligations using trust funds that have been established for this purpose. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios based upon significant estimates and assumptions, including decommissioning cost studies, cost escalation studies, probabilistic cash flow models and discount rates.

The following table provides a roll forward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from December 31, 2008 to June 30, 2009:


	Exelon and Generation
Nuclear decommissioning AROs at December 31, 2008(a)	$	3,485
Accretion expense		104
Increase due to changes in estimated cash flows		4
Payments to decommission retired plants		(8	)

Nuclear decommissioning AROs at June 30, 2009(a)	$	3,585

(a)	Includes $13 million as the current portion of the ARO at June 30, 2009 and December 31, 2008, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation’s obligations related to the shortfall or excess of trust funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the nuclear decommissioning trust funds exceed the total estimated decommissioning obligation, decommissioning-related activities recognized in the Consolidated Statement of Operations, including realized and unrealized income and losses on the trust funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the

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Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the value of the trust fund for any former ComEd unit fall below the amount of the estimated decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. At June 30, 2009, the trust funds of each of the former ComEd units exceeded the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is the obligation reflected on Generation’s Consolidated Balance Sheet at June 30, 2009 calculated in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Based on the regulatory agreement with the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the nuclear decommissioning trust funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities recognized in the Consolidated Statement of Operations are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and the impact to Exelon’s and Generation’s results of operations and financial position could be material. See Note 3 – Regulatory Issues for information regarding a PAPUC investigation to determine if PECO’s decommissioning cost collections from customers should continue after December 31, 2010.

The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the unregulated portions of the Peach Bottom nuclear plants (collectively, the Unregulated Units) are reflected in Exelon’s and Generation’s Consolidated Statements of Operations, as there are no regulatory agreements associated with these units.

NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. During 2008, the value of the trust funds declined significantly due to unrealized losses as a result of adverse financial market conditions. Despite this decline in value, Generation believes that the decommissioning trust funds for the nuclear generating stations formerly owned by ComEd, PECO and AmerGen, the expected earnings thereon and, in the case of the former PECO stations, the remaining amounts to be collected from PECO’s customers will ultimately be sufficient to fully fund Generation’s decommissioning obligations for its nuclear generating stations in accordance with NRC regulations.

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit

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or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial position may be significantly adversely affected.

Generation’s most recent report was filed with the NRC on March 31, 2009, based on trust fund values and estimated decommissioning obligations as of December 31, 2008. The estimated decommissioning obligations for the NRC report were calculated in accordance with NRC regulations and may differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets at December 31, 2008, primarily due to differences in assumptions regarding the decommissioning alternatives to be used and potential license renewals. In its NRC filing, Generation stated that it is evaluating the remedy to be utilized to address the underfunded status and such remedy will be in accordance with NRC regulations and guidance.

On July 13, 2009, the NRC published a summary of decommissioning trust fund shortfalls at industry nuclear units, which for Generation’s nuclear generating stations set forth an aggregate underfunded position of approximately $1.0 billion. The NRC calculation assumes one scenario where decommissioning activities are completed within seven years after the cessation of plant operations. Under NRC regulations, nuclear unit owners have up to 60 years to complete decommissioning after the cessation of operations, during which time decommissioning funds would continue to grow. The NRC did not publish any calculations for alternative scenarios where decommissioning activities are completed at a later time during the 60-year window. Consistent with studies approved by the NRC and assuming that decommissioning activities are completed within the permissible 60 year regulatory time period, Generation believes that six units at three nuclear generating stations were in an underfunded position by approximately $185 million in total relative to the NRC minimum funding requirement as of December 31, 2008. Over 90% of this total is attributable to Generation’s four units at Braidwood and Byron, where Generation has not yet filed for license extensions. Although the NRC does not allow for potential license extensions to be credited in calculating NRC minimum funding requirements, to the extent that license extensions are granted for these units, decommissioning funds will continue to grow for an additional 20-year period. Generation presently anticipates that it will file for license extensions for these units consistent with its ongoing business plan.

Generation and other industry members are engaged in ongoing discussions with the NRC regarding the NRC’s calculations. By July 31, 2009, Generation is required to submit to the NRC a plan for remediating the underfunded position of its units. The time frame for implementing this plan is subject to further discussion with the NRC.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. At present, subject to board of directors approval, Generation anticipates that it will remedy any underfunded position remaining after full implementation of its funding assurance plan as submitted to and approved by the NRC through the issuance of some form of financial guarantee rather than through cash contributions to the decommissioning trust funds.

Spent Nuclear Fuel Storage

Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the development of a repository for and the disposal of spent nuclear fuel (SNF) and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for

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disposal of SNF from its nuclear generating stations. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. In June 2008, in conjunction with the DOE filing a license application with the NRC for the first national repository for SNF and high-level radioactive waste at Nevada’s Yucca Mountain, the DOE indicated that, based on the time required for the NRC’s review process and the construction of the repository, the earliest the repository could be in operation would be 2020. Also, in January 2009, the DOE issued its Draft National Transportation Plan for the proposed repository at Yucca Mountain. DOE’s press statement accompanying the release of the plan indicated that shipments to the repository are not expected to begin before 2020. Based on the foregoing, Generation has considered the 2020 date as its best estimate of when DOE will begin accepting SNF. Currently, the 2020 date is used in the estimate of Generation’s nuclear asset retirement obligation and the fair value disclosure of its SNF obligation.

The 2010 Federal budget (which will take effect October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devises a new strategy for SNF disposal. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or SNF reprocessing. Because there is no particular date after 2020 that Generation can establish as having a higher probability as the start date for the DOE acceptance of SNF and because 2020 is a reasonable date for the use of an alternative strategy such as centralized interim storage, Generation continues to use 2020 as its best estimate of when the DOE will begin accepting SNF. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2025 and 2035 and determined that Generation’s aggregate nuclear asset retirement obligation would be reduced by an immaterial amount in each scenario. See Note 6 – Fair Value of Assets and Liabilities and Notes 12 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for additional information.

Nuclear Decommissioning Trust Fund Investments

At June 30, 2009 and December 31, 2008, Exelon and Generation had nuclear decommissioning trust fund investments totaling $5,850 million and $5,500 million, respectively.

In the first quarter of 2009, Generation performed a rebalancing of its decommissioning trust fund investments in order to bring the mix of equity and fixed income investments into alignment with targeted ratios. At June 30, 2009, approximately 50% of the funds were invested in equity and 50% were invested in fixed income securities. At December 31, 2008, approximately 39% of the funds were invested in equity and 61% were invested in fixed income securities.

Generation’s decommissioning trust funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities.

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Collateral may not be sold or re-pledged by the trustees, however, the borrowers may sell or re-pledge the securities loaned. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from current market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.

In the fourth quarter of 2008, Generation decided to end its participation in the securities lending program. However, Generation has chosen to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the lack of liquidity in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 6 months. At December 31, 2008, Generation had $380 million of loaned securities outstanding and held $386 million of related collateral under its lending agreements. At June 30, 2009, Generation had $164 million of loaned securities outstanding and held $165 million of related collateral under its lending agreements, representing a decrease in loaned securities outstanding since December 31, 2008 of $216 million primarily due to the return of loaned securities. Of the balance of loaned securities outstanding at June 30, 2009 (in terms of value), approximately 60% is expected to be returned by the end of 2009 with the remainder expected to be returned primarily in 2010.

A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the trust funds is included in trust fund earnings and classified as Other, Net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three and six months ended June 30, 2009 and 2008.

The following table provides unrealized gains (losses) on decommissioning trust funds for the three and six months ended June 30, 2009 and 2008:


	Exelon and Generation
	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Net unrealized gains (losses) on decommissioning trust funds — Regulated Units (a)	$	426	$	(111	)	$	258	$	(335	)
Net unrealized gains (losses) on decommissioning trust funds — Unregulated Units (b)		115		(29	)		51		(99	)

(a)

Generation’s nuclear decommissioning trust funds associated with the former ComEd and former PECO nuclear generating units (Regulated Units) are subject to contractual elimination pursuant to regulatory accounting and included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)	Generation’s nuclear decommissioning trust funds associated with the Unregulated Units are included within other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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Interest and dividends on nuclear decommissioning trust fund investments are recognized when earned and included in Other, Net in Exelon’s and Generation’s Consolidated Statements of Operations.

Refer to Note 17 — Related-Party Transactions for information regarding intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

13. Earnings Per Share and Equity (Exelon)

Earnings per Share

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
Income from continuing operations	$	658		$	749		$	1,369	$	1,330
Loss from discontinued operations		(1	)		(1	)		—		(1	)

Net income	$	657		$	748		$	1,369	$	1,329

Average common shares outstanding — basic		659			657			659		658
Assumed exercise of stock options, performance share awards and restricted stock		2			5			2		5

Average common shares outstanding — diluted		661			662			661	$	663

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 6 million and 5 million for the three and six months ended June 30, 2009, respectively, and 1 million and zero for the three and six months ended June 30, 2008, respectively.

Share Repurchases

As part of its value return policy, Exelon uses share repurchases from time to time to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities. In 2008, Exelon management decided to defer indefinitely any share repurchases. This decision was made in light of a variety of factors, including: developments affecting the world economy and commodity markets, including those for electricity and gas; the continued uncertainty in capital and credit markets and other potential impact of those events on Exelon’s future cash needs; projected cash needs to support investment in the business, including maintenance capital and nuclear uprates; and value-added growth opportunities, including possible acquisitions such as the then-proposed acquisition of NRG Energy, Inc.

Under share repurchase programs, 34.8 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of June 30, 2009. During the six months ended June 30, 2009 and 2008, Exelon repurchased 0 and 6.6 million shares of common stock, respectively, for $0 and $500 million, including the impact of the settlement of forward contracts, respectively.

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

For information regarding capital commitments at December 31, 2008, see Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K. All significant contingencies are disclosed below.

Energy Commitments

Generation’s, ComEd’s and PECO’s short and long-term commitments relating to the sale to and purchase from unaffiliated utilities and others of energy, capacity and transmission rights as of June 30, 2009 did not change significantly from December 31, 2008, except for the following:

•

Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $535 million during the six months ended June 30, 2009, reflecting increases of approximately $503 million, $594 million, $277 million, $26 million and $5 million related to 2010, 2011, 2012, 2013 and 2014 and beyond sales commitments, respectively, offset by the fulfillment of approximately $870 million of 2009 commitments during the six months ended June 30, 2009. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 8 – Derivative Financial Instruments for additional information regarding Generation’s hedging program.

•

In May 2009, ComEd entered into procurement contracts to enable ComEd to meet a portion of its customers’ electricity requirements for the period from June 2009 to May 2011. These contracts resulted in an increase in ComEd’s energy commitments of $252 million for the remainder of 2009, $269 million for 2010 and $31 million for 2011. See Note 3 – Regulatory Issues for further information.

Fuel and Natural Gas Purchase Obligations

Generation’s and PECO’s fuel purchase obligations as of June 30, 2009 did not change significantly from December 31, 2008, except for the following:

•

Generation’s total fuel purchase obligations for nuclear and fossil generation increased by approximately $3,505 million during the six months ended June 30, 2009, reflecting increases of approximately $132 million, $324 million, $392 million, $477 million and $2,642 million for 2010, 2011, 2012, 2013 and 2014 and beyond, respectively, due to contracts entered into in the normal course of business, offset by the fulfillment of approximately $462 million of 2009 commitments during the six months ended June 30, 2009.

•

PECO’s total natural gas obligations increased by approximately $50 million during the six months ended June 30, 2009, reflecting increases of $20 million, $24 million and $6 million in 2009, 2010 and 2011, respectively, primarily related to increased natural gas purchase commitments made in accordance with PECO’s PAPUC-approved procurement schedule.

Commercial and Construction Commitments

Exelon’s, Generation’s, ComEd’s and PECO’s commercial and construction commitments as of June 30, 2009, representing commitments potentially triggered by future events, did not change significantly from December 31, 2008, except for the following:

•

Exelon’s letters of credit decreased $55 million and guarantees decreased by $201 million primarily as a result of energy trading activities and the reorganization of AmerGen, which was merged into Generation effective January 8, 2009.

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•

Generation’s letters of credit increased by $28 million and guarantees decreased by $192 million primarily as a result of energy trading activities and the reorganization of AmerGen, which was merged into Generation effective January 8, 2009.

•

In May 2009, ComEd entered into contracts for the procurement of RECs totaling approximately $31 million. Through June 30, 2009, $12 million had been purchased, with $19 million to be purchased by May 31, 2010. See Note 3 — Regulatory Issues for additional information.

•

ComEd’s PJM regional transmission expansion plan (RTEP) baseline project commitments decreased by $28 million, $32 million and $5 million for 2009, 2010 and 2013, respectively, and increased by $23 million for 2010 and 2011 driven by changes in estimated timing and amount of project spending.

•

PECO’s outstanding letters of credit decreased by $83 million primarily due to the reduction in the collateral requirement with PJM based on an agreement executed in February 2009 between PECO, Generation and PJM that changed the way that PECO and Generation administer their PPA for default service.

•

PECO’s PJM RTEP baseline project commitments increased by $3 million in both 2011 and 2012 due to the addition of newly designated RTEP projects.

•

PECO’s AEC purchase commitments were not significant as of December 31, 2008. As of June 30, 2009, the commitments were $6 million for the remainder of 2009, $8 million for 2010, $9 million for 2011, 2012 and 2013 and $4 million for 2014. See Note 3 — Regulatory Issues for additional information.

Indemnifications Related to Sithe (Exelon and Generation)

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

In connection with the sale, Exelon recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. These indemnifications and guarantees are being accounted for under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others”. As of June 30, 2009, Exelon’s accrued liabilities related to these indemnifications and guarantees were $8 million. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $175 million at June 30, 2009.

Indemnifications Related to Sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP) (Exelon and Generation)

On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guaranty agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII’s ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guaranty that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guaranty is $95 million as of June 30, 2009. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guaranty began to expire in 2008.

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Environmental Liabilities

General (Exelon, Generation, ComEd and PECO)

The Registrants’ operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. ComEd and PECO have identified 42 and 27 sites, respectively, where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several Potentially Responsible Parties (PRPs) which may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of ten sites and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection (PA DEP) has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 21 and nine sites, respectively, are currently under some degree of active study and/or remediation. ComEd and PECO anticipate that the majority of the remediation at these sites will continue through at least 2015 and 2020, respectively. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

ComEd and Nicor Gas Company, a subsidiary of Nicor Inc. (Nicor), were parties to an interim agreement under which they cooperated in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, have responsibility. In January 2008, ComEd and Nicor executed a definitive written agreement on the allocation of costs for the MGP sites, which was approved by the ICC on June 9, 2009. The approval of the settlement by the ICC did not have an impact on ComEd’s cash flows or results of operations during the three or six months ended June 30, 2009 and ComEd’s accrual as of June 30, 2009 for these environmental liabilities reflects the cost allocations defined in the agreement. ComEd will continue to pass through to customers these environmental clean up costs pursuant to a rider approved by the ICC.

Based on the final order received in ComEd’s 2005 Rate Case, beginning in 2007, ComEd is recovering from customers a provision for environmental costs for the remediation of former MGP facility sites, including those incorporated in the Nicor Settlement, for which ComEd has recorded a regulatory asset. Based on the final order received from the PAPUC, PECO is currently recovering from customers a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. The gas distribution rate settlement approved in 2008 supports the recovery, on an annual basis, of $3.5 million for the remediation of PECO’s former MGP sites based on an 8-year estimated remaining duration of PECO’s MGP remediation program. See Note 15 — Supplemental Financial Information for additional information regarding regulatory assets and liabilities.

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As of June 30, 2009 and December 31, 2008, Exelon, Generation, ComEd and PECO accrued the following amounts for environmental liabilities:

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, including customers.

Section 316(b) of the Clean Water Act. In July 2004, the United States Environmental Protection Agency (EPA) issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Since promulgation of the rule, Generation has been evaluating compliance options at its affected plants and meeting interim compliance deadlines.

On January 25, 2007, the U.S. Second Circuit Court of Appeals issued its opinion in a challenge to the final Phase II rule. The court found that with respect to a number of significant provisions of the rule the EPA exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the rule back to the EPA for revisions consistent with the court’s opinion. By its action, the court invalidated compliance measures which were supported by the utility industry because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. The court’s opinion has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. On July 9, 2007, the EPA formally suspended the Phase II rule. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures.

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On April 14, 2008, the U.S. Supreme Court granted a petition filed by the industry parties on the issue of whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On April 1, 2009, the Supreme Court issued a ruling that the EPA has the discretion to use a cost-benefit analysis under Section 316(b) and reversed the decision of the U.S. Second Circuit Court of Appeals that had invalidated the use of a cost-benefit test. The EPA will now take up consideration of the rule on remand and take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010, and it is uncertain how the U.S. Supreme Court’s decision will affect that timing.

Due to the regulatory uncertainties, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. If the final rule, or interim state requirements under best professional judgment, has performance standards that require the reduction of cooling water intake flow at the plants consistent with closed cycle cooling systems, then there could be a material adverse impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, cash flows and financial positions.

In a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. In light of the suspension of the Phase II rule by the EPA, the NJDEP advised Generation that it will issue a new draft permit, and reiterated its preference for cooling towers as the best technology available in the exercise of its best professional judgment. Oyster Creek has operated and will continue to operate under the 1994 permit until a new permit is issued. Generation cannot predict with any certainty how the NJDEP will implement its best professional judgment nor how Oyster Creek will be affected by the final regulations once they are issued by the EPA as discussed above. In addition, the cost required to retrofit Oyster Creek with closed cycle cooling, if required by a new permit or the revised EPA regulations, would be material and would therefore negatively impact Generation’s decision to operate the plant after the NJDEP permit and Section 316(b) matters are ultimately resolved.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised Public Service Enterprise Group (PSEG) in July 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. PSEG continues to operate Salem under the approved June 2001 NJDPES permit while the NJDPES permit renewal application is being reviewed. If application of the final 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, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

Nuclear Generating Station Groundwater. On December 16, 2005 and February 27, 2006, the Illinois EPA issued violation notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station (Braidwood).

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In November 2005, Generation discovered that spills from the line in 1996, 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels in portions of the plume exceed Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant showed that, with one exception, tritium levels in these wells were at levels that naturally occur. The tritium level in one drinking water well was elevated above levels that occur naturally, but was significantly below the state and Federal drinking water standards, and Generation believes that this level posed no threat to human health. Generation has investigated the causes of the releases and has taken the necessary corrective actions to prevent another occurrence. Generation notified the owners of 14 potentially affected adjacent properties that, upon sale of their property, Generation will reimburse the owners for any diminution in property value caused by the tritium release.

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 there have been tritium and other non-radioactive wastes discharged from Braidwood in violation of Braidwood’s NPDES permit, the Illinois Environmental Protection Act and regulations of the Illinois Pollution Control Board. The lawsuit seeks the maximum civil penalties allowed, injunctive relief relating to the discontinuation of the liquid tritium discharge line until additional court order, soil and groundwater testing, prevention of future releases and off-site migration, and provision of potable drinking water to area residents. On May 24, 2006, the Circuit Court entered an order resulting in Generation commencing remediation efforts in June 2006 for tritium in groundwater off of plant property. Any civil penalty will not be determined until the consent decree is finalized. Generation is unable to determine the amount of the penalty that it will ultimately be required to pay.

Generation detected small underground tritium leaks at the Dresden Nuclear Generating Station (Dresden) and at the Byron Nuclear Generating Station (Byron) in 2006. Neither of these discharges occurred outside the property lines of the plant, nor does Generation believe either of these matters poses health or safety threats to employees or to the public. Generation identified the source of the leaks and implemented repairs. On March 31, 2006 and April 12, 2006, the Illinois EPA issued an NOV to Generation in connection with the Dresden and Byron leaks. The Illinois EPA has rejected the remediation plans submitted by Generation for each station and is currently pursuing legal action against Generation.

Generation is discussing the violation notices and Illinois Attorney General civil enforcement matters for Braidwood, Dresden and Byron, discussed above, with the Illinois EPA, the Illinois Attorney General and the State’s Attorney for the Counties in which the plants are located. Generation believes that appropriate reserves have been recorded for State of Illinois fines and remediation costs in accordance with SFAS No. 5 as of June 30, 2009 and December 31, 2008.

As part of its normal operations, Generation performs on-going environmental monitoring at its sites. Generation’s monitoring activities sometimes detect the release of measurable levels of tritium, a weak radioactive isotope of hydrogen that is produced and released at all nuclear sites and also is released naturally through the interaction of sunlight and water molecules. These releases do not pose a threat to Generation’s employees, the public, or the environment. Generation has reported, and may in the future report such tritium releases to soil or groundwater at its stations.

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.

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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. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs. The current estimated cost of the anticipated remediation for the site is $37 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.

Air. During March 2005, the EPA finalized several new rulemakings designed to reduce power plant emissions of SO₂, NO_x and mercury. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the Clean Air Interstate Rule (CAIR), which had been promulgated by the EPA to reduce power plant emissions of SO₂ and NO_x. On September 25, 2008, EPA petitioned the Court for re-hearing of the CAIR decision. In response to the September petition, on December 23, 2008, the Court elected to remand the CAIR to the EPA, without invalidating the entire rulemaking, so that EPA may remedy “CAIR’s flaws” in accordance with the Court’s July 11, 2008 opinion. This decision allows the CAIR to remain in effect until it is replaced by a rule consistent with the Court’s July 11 opinion. In its December opinion, the Court elected not to establish a particular schedule for EPA to revise its rulemaking; however, the Court indicated that its remand did not represent an indefinite stay of the Court’s original opinion and that petitioners retained the right to petition the Court to impose a deadline on the EPA in the event that EPA fails to modify its CAIR regulations as directed by the Court, on a timely basis. The EPA is expected to issue a new proposed CAIR rulemaking in early 2010. At this time, Exelon is unable to predict the exact approach that will be utilized by EPA to revise its CAIR regulation, how long the current CAIR program will remain in effect, or what steps individual states may take in response to the CAIR situation.

On March 5, 2009, the D.C. Circuit Court of Appeals remanded Sierra Club and Environment North Carolina vs. EPA back to the EPA for the EPA to reconsider its denial of North Carolina’s Section 126 petition, originally filed in 2004, that requested that the EPA impose NO_x and SO₂ emission reduction requirements on various named upwind states (including Illinois and Pennsylvania) whose air emissions North Carolina contended were contributing significantly to nonattainment in North Carolina. The EPA had originally taken the position that the CAIR would be satisfactory to provide North Carolina with needed upwind emission reductions and deferred action on North Carolina’s petition. With the Court remand of CAIR for revision, the EPA has agreed to re-visit North Carolina’s Section 126 petition for potential rulemaking and could attempt to address North Carolina’s concerns as part of its CAIR revisions or via a separate rulemaking. Due to the uncertainty as to any of the potential outcomes related to CAIR and North Carolina’s Section 126 petition, Exelon cannot estimate the effect of the decision on its operations and its future competitive position, results of operations, earnings, cash flows and financial position.

In a separate rulemaking issued in March 2005, the EPA finalized the Clean Air Mercury Rule (CAMR), which is a national program to cap mercury emissions from coal-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR on the basis that the EPA had failed to properly de-list mercury as a hazardous air pollutant (HAP) under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to hazardous air pollutants. On February 23, 2009, the U.S. Supreme Court declined to review the U.S. Court of Appeals’ CAMR decision. The EPA is now

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expected to propose a new rulemaking, likely in early 2010, to address HAP emissions from electric generation power plants. In addition to regulation at the national level, Exelon had been subject to more stringent mercury regulation (PA Mercury Rule) enacted in 2006 at the state level in Pennsylvania. However, on January 30, 2009, the Commonwealth Court of Pennsylvania ruled that the PA Mercury Rule is unlawful and invalid and enjoined the state from continued implementation and enforcement of the rule. The PA DEP has appealed to the Commonwealth Supreme Court seeking re-instatement of the rule. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal and state regulations are finalized upon the completion of agency rulemakings and court appeals.

Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received an NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Federal Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The EPA requested information related to the stations in 2003, and ComEd has been cooperating with the EPA since then. The NOV states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the Clean Air Act.

The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and accordingly, have not recorded a reserve for the NOV.

On January 14, 2009, Generation received an NOV, addressed to it, the other owners of Keystone Generating Station (Keystone) and Reliant Energy Northeast Management Company (the operator of Keystone) from the EPA, alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Keystone, as well as two other stations currently owned and operated by Reliant Energy in which Generation has no ownership interest. Generation has been cooperating with the EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the Clean Air Act. At this time, Exelon and Generation are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation; however, Exelon and Generation have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

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On April 16, 2009, the EPA issued an NOV to ComEd and Dominion Resources Services, Inc. (Dominion) alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Kincaid electric generating station located in Illinois and State Line electric generating station located in Indiana. Kincaid was sold by ComEd in 1998 and State Line was sold by Commonwealth Edison of Indiana in 1997. Both stations are currently owned and operated by Dominion. The EPA requested information related to the stations in 2009, and ComEd has been cooperating with the EPA since the time of that request. The NOV states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements, each party agreed to indemnify the other for certain environmental activities, events, conditions or occurrences arising before and after the purchase of the stations; however, Exelon, Generation, and ComEd are unable at this time to determine how those provisions may apply to any liability or cost that may eventually arise out of the NOV or any resulting enforcement action.

In connection with Exelon Corporation’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations related to ComEd’s former generation business, which would include any responsibility under the indemnification provisions contained in the sale agreements related to Kincaid and State Line stations. At this time, Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation or ComEd; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

Voluntary Greenhouse Gas Emissions Reductions. Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its greenhouse gas (GHG) emissions by 8% from 2001 levels by the end of 2008. Exelon made this pledge under the United States EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. As of December 31, 2008, Exelon had achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the previous closure of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and its current energy efficiency initiatives. On March 12, 2009, Exelon submitted its final GHG inventory documentation, including a third-party verification report, to the EPA for final agency review. On April 6, 2009, the EPA notified Exelon that it had reviewed the documents submitted and confirmed that Exelon had exceeded its voluntary goal. The cost of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s future competitive position, results of operations, earnings, financial position or cash flows.

On July 15, 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental plan. The plan, Exelon 2020, details an enterprise-wide approach and a host of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and that of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of greenhouse gas emissions per year by 2020 (from 2001 levels).

Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing the vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s new portfolio of energy efficiency programs, a

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similar portfolio of energy efficiency programs at PECO to meet the requirements of the recently enacted PA Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power, adding capacity to existing nuclear plants through uprates, and through the potential addition of new low-carbon natural gas and nuclear generation.

Exelon has incorporated Exelon 2020 into its overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. Exelon has recently completed a periodic review of the original analysis of the costs and abatement potential of various emissions-reducing opportunities and remains committed to achieving the goal put forward in 2008. Specific initiatives and the amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

One of the key policy developments that could affect the Exelon 2020 roadmap is enactment of Federal climate change legislation. Federal legislation is currently under consideration in the U.S. Congress, with H.R. 2454, “The American Clean Energy and Security Act of 2009,” as the primary vehicle. H.R. 2454, which Exelon supported, was approved by the U.S. House of Representatives on June 26, 2009 and would affect electric generation and electric and natural gas distribution companies. A key provision of H.R. 2454 is the establishment of mandatory, economy-wide GHG reduction targets and goals via a Federal emissions cap-and-trade program. The program would begin in 2012 and calls for a three percent reduction below 2005 levels in 2012, with the reduction requirement increasing to 17% below 2005 levels by 2020 and ultimately 83% below 2005 levels by 2050. The legislation also contains several energy efficiency and clean energy requirements. Of particular note for electric retail supply companies, there is a proposed requirement that 20% of electricity sold by retail suppliers be met by energy efficiency and renewable energy by 2020. The requirement begins to phase-in starting in 2012 at a 6% level and escalates every two years until it reaches 20% in 2020. Following passage of H.R. 2454, key Senate committees began hearings on comprehensive energy and GHG legislation. The Senate is expected to consider its own version of the legislation sometime later in 2009 or in 2010.

Regulation of GHG emissions under the Clean Air Act. On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U. S. Environmental Protection Agency holding that CO2 and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for additional rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule and Federal or state legislation. In response to the Supreme Court decision, on July 11, 2008, the EPA issued an Advance Notice of Proposed Rulemaking (ANPR) to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act.

On March 10, 2009, the EPA released a proposed mandatory GHG reporting rulemaking for public comment. This rulemaking proposes to require that large GHG emissions sources (greater than 25,000 metric tons per year of GHG emissions) begin reporting their emissions starting in 2011. The EPA indicates that the reporting rule will cover over 85% of total national U.S. GHG emissions and that emissions data collected will be used to inform future policy decisions. On April 17, 2008, the EPA issued a proposed endangerment finding

100

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under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles. The proposed endangerment finding is subject to public comment, and when final will not result automatically in new emissions controls, which will occur upon further rulemaking. While the proposal does not specifically address stationary sources, such as a generating plant, the general endangerment finding relative to GHG’s in the atmosphere would support such a proposal by the EPA for stationary sources.

The issue of GHG regulation will likely be addressed either under the Clean Air Act or by new and comprehensive Federal legislation. The Obama administration and the EPA have stated a preference for addressing the issue through Federal legislation. Due to the uncertainty as to the final outcome of Federal climate change legislation, Exelon cannot definitively estimate the effect of GHG regulation on its operations and its future competitive position, results of operations, cash flows and financial position.

Litigation and Regulatory Matters

Exelon and Generation

Asbestos Personal Injury Claims. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At June 30, 2009 and December 31, 2008, Generation had reserved approximately $50 million and $52 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2009, approximately $12 million of this amount related to 144 open claims presented to Generation, while the remaining $38 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During 2009 and 2008, the updates to this reserve did not result in material adjustments.

Exelon

Pension Claim. On July 11, 2006, a former employee of ComEd filed a purported class action lawsuit against the Exelon Corporation Cash Balance Pension Plan (Plan) in the Federal District Court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculated lump sum distributions in a manner that does not comply with the Employee Retirement Income Security Act (ERISA). The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions since 2001 and injunctive relief with respect to future lump sum distributions. On August 31, 2007, the District Court dismissed the lawsuit in its entirety. On December 21, 2007, the District Court amended its order, in part, to allow the plaintiff to file an administrative claim with the Plan with respect to the calculation of the portion of his lump sum benefit accrued under the Plan’s prior traditional formula. On July 2, 2009, the U.S. Court of Appeals for the Seventh Circuit affirmed the District Court’s dismissal of his claims and, on July 14, 2009, the plaintiff filed a motion requesting rehearing of the case before the entire Seventh Circuit Court of Appeals. In addition, on January 6, 2009, the plaintiff filed a complaint in the District Court challenging the Plan’s denial of his administrative claim. The ultimate outcome of the pension claim is uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

101

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Savings Plan Claim. On September 11, 2006, five individuals claiming to be participants in the Exelon Corporation Employee Savings Plan, Plan #003 (Savings Plan), filed a putative class action lawsuit in the United States District Court for the Northern District of Illinois. The complaint names as defendants Exelon, its Director of Employee Benefit Plans and Programs, the Employee Savings Plan Investment Committee, the Compensation and the Risk Oversight Committees of Exelon’s Board of Directors and members of those committees. The complaint alleges that the defendants breached fiduciary duties under ERISA by, among other things, permitting fees and expenses to be incurred by the Savings Plan that allegedly were unreasonable and for purposes other than to benefit the Savings Plan and participants, and failing to disclose purported “revenue sharing” arrangements among the Savings Plan’s service providers. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Savings Plan and participants, including alleged investment losses. On February 21, 2007, the district court granted the defendants’ motion to strike the plaintiffs’ claim for investment losses. On June 27, 2007, the district court granted the plaintiffs’ motion for class certification. On June 28, 2007, the district court granted the defendants’ motion to stay proceedings in this action pending the outcome of the appeal to the U.S. Seventh Circuit Court of Appeals in another case not involving Exelon. In that case, the U.S. District Court for the Western District of Wisconsin dismissed with prejudice substantially similar claims. On February 12, 2009, a panel of the Seventh Circuit Court of Appeals affirmed the district court’s dismissal of that case and, on March 9, 2009, the plaintiffs’ motion requesting a rehearing of that case before the entire Seventh Circuit Court of Appeals was denied. On July 9, 2009, the defendants in the Exelon case filed a motion requesting that the district court lift the stay and enter judgment in the defendants’ favor. The ultimate outcome of the savings plan claim is uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

Retiree Healthcare Benefits Grievance. In 2006, Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15) filed a demand for arbitration of a grievance challenging certain changes implemented in 2004 to the health care coverage provided to retirees who were members of IBEW Local 15 during their employment with Exelon, Generation and ComEd. Exelon then filed a lawsuit in the U.S. District Court for the Northern District of Illinois seeking a judicial determination that this grievance is not arbitrable as disputes regarding benefits provided to current retirees are not within the scope of the collective bargaining agreement. On December 3, 2007, the U.S. District Court ruled that, under the terms of the parties’ collective bargaining agreement, IBEW Local 15 could use the collective bargaining agreement’s grievance and arbitration procedure to challenge these changes with respect to retirees named in the grievance. On September 8, 2008, the U.S. Court of Appeals for the Seventh Circuit affirmed the decision of the district court. A settlement agreement was reached between Exelon and IBEW Local 15 on February 19, 2009 that included certain prospective changes to the healthcare benefits provided to retirees who were members of IBEW Local 15 during their Exelon employment. These changes become effective at various times between May 1, 2009 and January 1, 2013 and resulted in withdrawal of the grievance. The settlement agreement will be treated as a plan amendment in the related welfare plan and reflected in the plan’s next measurement. The settlement agreement will not have a material impact on Exelon’s, Generation’s or ComEd’s results of operations, cash flows or financial position.

Exelon, Generation, ComEd and PECO

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

102

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Exelon and ComEd

Reliability. On July 18, 2008, ComEd self-reported to ReliabilityFirst Corporation, its Regional Entity, that it failed to maintain vegetation clearance on a section of a transmission line, constituting a violation of a North American Electric Reliability Corporation (NERC) reliability standard. ComEd is subject to potential fines for a violation of NERC reliability standards. The ultimate outcome of this matter remains uncertain but ComEd does not believe it would result in a material unfavorable impact to ComEd’s consolidated financial statements.

Agreement Related to Sale of Accounts Receivable

Exelon and PECO

PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable, which PECO accounted for as a sale under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities — a Replacement of FASB Statement No. 125,” (SFAS No. 140). PECO retains the servicing responsibility for the sold receivables and has recorded a servicing liability in accordance with SFAS No. 156, “Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140,” (SFAS No. 156). The agreement terminates on September 18, 2009, unless extended in accordance with its terms. As of June 30, 2009, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and will seek alternate financing. See Note 6 — Fair Value of Assets and Liabilities for additional information regarding the servicing liability.

Income Taxes

See Note 11 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

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

Supplemental Statement of Operations Information

The following tables provide additional information regarding the components of depreciation, amortization, and accretion, and other, net within the Consolidated Statements of Operations and Comprehensive Income of Exelon, Generation, ComEd and PECO for the three and six months ended June 30, 2009 and 2008:


Three Months Ended June 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	237	$	72	$	112	$	40
Regulatory assets(a)		202		—		12		190
Nuclear fuel(b)		139		139		—		—
Asset retirement obligation accretion(c)		53		53		—		—

Total depreciation, amortization and accretion	$	631	$	264	$	124	$	230

(a)	For PECO, primarily reflects CTC amortization.

(b)	Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	475	$	149	$	221	$	80
Regulatory assets(a)		400		—		25		375
Nuclear fuel(b)		272		272		—		—
Asset retirement obligation accretion(c)		106		105		—		—

Total depreciation, amortization and accretion	$	1,253	$	526	$	246	$	455

(a)	For PECO, primarily reflects CTC amortization.

(b)	Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.


Three Months Ended June 30, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	227	$	73	$	105	$	38
Regulatory assets(a)		175		—		8		167
Nuclear fuel(b)		83		83		—		—
Asset retirement obligation accretion(c)		59		59		—		—

Total depreciation, amortization and accretion	$	544	$	215	$	113	$	205

(a)	For PECO, primarily reflects CTC amortization.

(b)	Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.


Six Months Ended June 30, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	449	$	143	$	207	$	78
Regulatory assets(a)		350		—		17		333
Nuclear fuel(b)		178		178		—		—
Asset retirement obligation accretion(c)		119		119		—		—

Total depreciation, amortization and accretion	$	1,096	$	440	$	224	$	411

(a)	For PECO, primarily reflects CTC amortization.

(b)	Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

The following tables set forth costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause for Exelon and ComEd for the three and six months ended June 30, 2009 and 2008. An equal and offsetting amount has been reflected in operating revenues during the period.


	Exelon and ComEd
(In millions)	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009
Operating and maintenance for regulatory required programs
Energy efficiency and demand response programs(a)	$	13	$	23
Purchased power administrative costs		1		2

Total operating and maintenance for regulatory required programs	$	14	$	25

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(a)	As a result of the 2007 Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. See Note 3 — Regulatory Issues for additional information.


	Exelon and ComEd
(In millions)	Three Months Ended June 30, 2008		Six Months Ended June 30, 2008
Operating and maintenance for regulatory required programs
Energy efficiency and demand response programs(a)	$	5	$	5
Purchased power administrative costs		1		1

Total operating and maintenance for regulatory required programs	$	6	$	6

(a)	As a result of the 2007 Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. See Note 3 — Regulatory Issues for additional information.

The following tables provide additional information regarding the components of other, net within the Consolidated Statements of Operations and Comprehensive Income of Exelon, Generation, ComEd and PECO for the three and six months ended June 30, 2009 and 2008:


Three Months Ended June 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Investment income	$	—		$	—		$	—		$	—
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)		10			10			—			—
Net realized income on decommissioning trust funds — Unregulated Units(a)		10			10			—			—
Net unrealized gains on decommissioning trust funds — Regulated Units		426			426			—			—
Net unrealized gains on decommissioning trust funds —Unregulated Units		115			115			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(349	)		(349	)		—			—
Net direct financing lease income		7			—			—			—
Interest income related to uncertain income tax positions(c)		38			—			59			2
Other-than-temporary impairment to Rabbi trust investments(d)		(7	)		—			(7	)		—
Other		7			3			3			1

Other, net	$	257		$	215		$	55		$	3

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

Includes the elimination of decommissioning trust fund-related activity for the Regulated Units, which are subject to regulatory accounting, including the elimination of net realized income, net unrealized gains and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.

(c)	Primarily includes interest income at Generation and ComEd related to the ITC Illinois Supreme Court decision and interest income recorded at ComEd from the 2009 remeasurement of income tax uncertainties. See Note 11 — Income Taxes for information regarding the Registrants’ tax positions.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 6 — Fair Value of Assets and Liabilities for additional information regarding the impairment.

105

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Investment income	$	1		$	—		$	—		$	1

Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)		28			28			—			—
Net realized income on decommissioning trust funds — Unregulated Units(a)		18			18			—			—
Net unrealized gains on decommissioning trust funds — Regulated Units		258			258			—			—
Net unrealized gains on decommissioning trust funds —Unregulated Units		51			51			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(234	)		(234	)		—			—
Net direct financing lease income		13			—			—			—
Interest income related to uncertain income tax positions(c)		77			4			87			3
Other-than-temporary impairment to Rabbi trust investments(d)		(7	)		—			(7	)		—
Other		14			8			7			2

Other, net	$	219		$	133		$	87		$	6

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

(c)	Primarily includes interest income at Generation and ComEd related to the ITC Illinois Supreme Court decision and interest income recorded at ComEd from the 2009 remeasurement of income tax uncertainties. See Note 11 — Income Taxes for information regarding the Registrants’ tax positions.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 6 — Fair Value of Assets and Liabilities for additional information regarding the impairment.

106

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Three Months Ended June 30, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Investment income	$	2		$	—		$	1	$	1

Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)		42			42			—		—
Net realized income on decommissioning trust funds — Unregulated Units(a)		10			10			—		—
Net unrealized losses on decommissioning trust funds — Regulated Units		(111	)		(111	)		—		—
Net unrealized losses on decommissioning trust funds — Unregulated Units		(29	)		(29	)		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		8			8			—		—
Net direct financing lease income		6			—			—		—
AFUDC, equity(c)		2			—			2		—
Interest income related to uncertain income tax positions		10			—			1		5
Income related to the termination of a gas supply guarantee(d)		13			13			—		—
Other		7			4			1		1

Other, net	$	(40	)	$	(63	)	$	5	$	7

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

Includes the elimination of decommissioning trust fund-related activity for the Regulated Units, which are subject to regulatory accounting, including the elimination of net realized income, net unrealized losses and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.

(c)	Includes reversal of previously recognized AFUDC resulting from the January 18, 2008 FERC order granting incentive treatment on ComEd’s largest transmission project. See Note 3 – Regulatory Issues for additional information.

(d)	Income related to the termination of a gas supply guarantee to Mystic Development LLC.

107

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Six Months Ended June 30, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Investment income	$	8		$	—		$	5	$	3

Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)		59			59			—		—
Net realized income on decommissioning trust funds — Unregulated Units(a)		4			4			—		—
Net unrealized losses on decommissioning trust funds — Regulated Units		(335	)		(335	)		—		—
Net unrealized losses on decommissioning trust funds — Unregulated Units		(99	)		(99	)		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		215			215			—		—
Net direct financing lease income		12			—			—		—
AFUDC, equity(c)		1			—			1		—
Interest income related to uncertain income tax positions		16			9			1		8
Income related to the termination of a gas supply guarantee(d)		13			13			—		—
Other		8			6			2		—

Other, net	$	(98	)	$	(128	)	$	9	$	11

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

Includes the elimination of decommissioning trust fund-related activity for the Regulated Units, which are subject to regulatory accounting, including the elimination of net realized income, net unrealized losses and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.

(c)	Includes reversal of previously recognized AFUDC resulting from the January 18, 2008 FERC order granting incentive treatment on ComEd’s largest transmission project. See Note 3 – Regulatory Issues for additional information.

(d)	Income related to the termination of a gas supply guarantee to Mystic Development LLC.

108

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Supplemental Cash Flow Information

The following tables provide additional information regarding the components of net fair value changes related to derivatives and nuclear decommissioning trust funds, other non-cash operating activities and changes in other assets and liabilities within the Registrants’ Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008:


Six Months Ended June 30, 2009	Exelon			Generation			ComEd			PECO
Net fair value changes related to derivatives and nuclear decommissioning trust funds:
Net mark-to-market gains on derivative transactions	$	28		$	28		$	—		$	—
Net unrealized and realized losses on nuclear decommissioning trust fund investments(a)		(43	)		(43	)		—			—

Total net fair value changes related to derivatives and nuclear decommissioning trust funds	$	(15	)	$	(15	)	$	—		$	—

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	263		$	120		$	96		$	23
Equity in losses of unconsolidated affiliates and investments		14			1			—			12
Provision for uncollectible accounts		65			3			25			38
Stock-based compensation costs		42			—			—			—
Other decommissioning-related activity(b)		(43	)		(43	)		—			—
Amortization of energy-related options		31			31			—			—
Amortization of regulatory asset related to debt costs		14			—			12			2
Amortization of the regulatory liability related to the PURTA tax settlement(c)		(2	)		—			—			(2	)
Other-than-temporary impairment to Rabbi trust investments(d)		7			—			7			—
Other		20			1			19			10

Total other non-cash operating activities	$	411		$	113		$	159		$	83

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	58		$	—		$	47		$	11
Other current assets		(152	)		(9	)(e)		3			(137	)(g)
Other noncurrent assets and liabilities		(205	)		(116	)(f)		(82	)		(2	)

Total changes in other assets and liabilities	$	(299	)	$	(125	)	$	(32	)	$	(128	)

(a)	Represents net unrealized gains and realized losses on sales of investments of the trust funds of the Unregulated Units. Net unrealized gains and realized losses on sales of investments of the trust funds of the Regulated Units are eliminated as a result of regulatory accounting.

(b)

Includes the elimination of decommissioning-related activity for the Regulated Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, asset retirement cost amortization, investment income and income taxes related to all trust fund activity. See Note 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)

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COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

refunding the amount to customers in January 2008. The regulatory liability associated with the PURTA settlement was fully amortized in January 2009.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 6 — Fair Value of Assets and Liabilities for additional information regarding the impairment.

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

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

(g)	Relates primarily to prepaid utility taxes.


Six Months Ended June 30, 2008	Exelon			Generation			ComEd			PECO
Net fair value changes related to derivatives and nuclear decommissioning trust funds:
Net mark-to-market gains on derivative transactions	$	(273	)	$	(222	)	$	—		$	—
Net unrealized and realized losses on nuclear decommissioning trust fund investments(a)		124			124			—			—

Total net fair value changes related to derivatives and nuclear decommissioning trust funds	$	(149	)	$	(98	)	$	—		$	—

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	158		$	70		$	50		$	16
Equity in losses of unconsolidated affiliates and investments		13			1			5			7
Provision for uncollectible accounts		97			(5	)		22			80
Stock-based compensation costs		38			—			—			—
Other decommissioning-related activity(b)		78			78			—			—
Amortization of energy-related options		3			3			—			—
Amortization of regulatory asset related to debt costs		14			—			12			2
Amortization of the regulatory liability related to the PURTA tax settlement(c)		(16	)		—			—			(16	)
Other		(2	)		(11	)		19			1

Total other non-cash operating activities	$	383		$	136		$	108		$	90

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(66	)	$	—		$	(49	)	$	(17	)
Other current assets		(207	)		(64	)(d)		(1	)		(72	)(f)
Other noncurrent assets and liabilities		(197	)		(198	)(e)		(14	)		(4	)

Total changes in other assets and liabilities	$	(470	)	$	(262	)	$	(64	)	$	(93	)

(a)	Represents net unrealized losses and realized losses on sales of investments of the trust funds of the Unregulated Units. Net unrealized losses and realized losses on sales of investments of the trust funds of the Regulated Units are eliminated as a result of regulatory accounting.

(b)

(c)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability and PECO began amortizing this liability and refunding customers in January 2008.

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

(f)	Relates primarily to prepaid utility taxes.

Supplemental Balance Sheet Information

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of June 30, 2009 and December 31, 2008:


June 30, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	1,294	$	—	$	1,294
Pension and other postretirement benefits		2,759		—		23
Deferred income taxes		831		15		816
Debt costs		157		136		21
Severance		105		105		—
Conditional asset retirement obligations		126		109		17
MGP remediation costs		114		74		40
Rate case costs		12		11		1
RTO start-up costs		13		13		—
Financial swap with Generation — noncurrent		—		752		—
Under-recovered universal service fund costs(a)		2		—		2
DSP Program electric procurement contracts(b)		2		—		2
Other		37		13		24

Noncurrent regulatory assets		5,452		1,228		2,240
Financial swap with Generation — current		—		285		—
Under-recovered energy and transmission costs current asset(c)		21		21		—

Total regulatory assets	$	5,473	$	1,534	$	2,240

Regulatory liabilities
Nuclear decommissioning	$	1,490	$	1,418	$	72
Removal costs		1,160		1,160		—
Deferred taxes		25		—		—
Over-recovered universal service fund costs(a)		2		—		2
Energy efficiency and demand response programs		12		12		—

Noncurrent regulatory liabilities		2,689		2,590		74
Over-recovered energy and transmission costs current liability(c)		27		1		26

Total regulatory liabilities	$	2,716	$	2,591	$	100

(a)	The universal services fund cost is a recovery mechanism that allows for PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of June 30, 2009, PECO was under - recovered for its electric program and over - recovered for its gas program.

(b)

Pursuant to the PECO’s PAPUC-approved DSP Program, PECO entered into block contracts to procure electric generation for its residential procurement class beginning January 1, 2011. As of June 30, 2009, PECO recorded a mark-to-market liability and this offsetting regulatory asset to account for changes in fair value. These block contracts were executed in accordance with the PAPUC-approved DSP Program and PECO will receive full cost recovery in rates.

111

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(c)

The ComEd under-recovered or over-recovered energy and transmission costs represent purchased power related costs recoverable or refundable to customers under ComEd’s regulatory approved rates. In addition, PECO’s over-recovered energy costs represent gas supply related costs refundable to customers under PECO’s PAPUC PGC. These costs are included in other current liabilities in Exelon’s, ComEd’s and PECO’s Consolidated Balance Sheets. ComEd and PECO pay a rate of return on over-recovered energy costs. See Note 3 — Regulatory Issues for additional information.


December 31, 2008	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	1,666	$	—	$	1,666
Pension and other postretirement benefits		2,855		—		26
Deferred income taxes		826		16		810
Debt costs		169		146		23
Severance		116		116		—
Conditional asset retirement obligations		128		112		16
MGP remediation costs		121		80		41
Rate case costs		15		14		1
RTO start-up costs		14		14		—
Financial swap with Generation — noncurrent		—		345		—
Other		30		15		14

Noncurrent regulatory assets		5,940		858		2,597
Financial swap with Generation — current		—		111		—
Under-recovered energy costs current asset(a)		58		58		—

Total regulatory assets	$	5,998	$	1,027	$	2,597

Regulatory liabilities
Nuclear decommissioning	$	1,336	$	1,289	$	47
Removal costs		1,145		1,145		—
Refund of PURTA taxes(b)		2		—		2
Deferred taxes		30		—		—
Energy efficiency and demand response programs		7		6		—

Noncurrent regulatory liabilities		2,520		2,440		49
Over-recovered energy costs current liability(a)		13		1		12

Total regulatory liabilities	$	2,533	$	2,441	$	61

(a)

(b)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability. PECO began amortizing this regulatory liability and refunding the amount to customers in January 2008. The regulatory liability associated with the PURTA settlement was fully amortized in January 2009.

112

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of June 30, 2009 and December 31, 2008:


June 30, 2009	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	8,579	(a)	$	3,991	(a)	$	1,978	$	2,393

Accounts receivable:
Allowance for uncollectible accounts		236			31			63		142

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,289 million.


December 31, 2008	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	8,242	(a)	$	3,812	(a)	$	1,866	$	2,345

Accounts receivable:
Allowance for uncollectible accounts		238			30			57		151

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,214 million.

The following tables provide information regarding Exelon’s and Generation’s option premiums as of June 30, 2009 and December 31, 2008:


Exelon and Generation	June 30, 2009		December 31, 2008
Other current assets:
Option premiums	$	236	$	308

Other current liabilities:
Option premiums		262		267

The following table provides information regarding dividends payable for Exelon as of June 30, 2009 and December 31, 2008:

The following tables provide additional information about accumulated other comprehensive income (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008.


June 30, 2009	Exelon			Generation		ComEd		PECO
Accumulated other comprehensive income (loss)
Minimum pension liability	$	(224	)	$	—	$	—	$	—
Adjustment to initially apply SFAS No. 158(a)		(1,268	)		—		—		—
Net unrealized gain on cash-flow hedges		867			1,512		—		2
Pension and non-pension postretirement benefit plans		(1,248	)		—		—		—

Total accumulated other comprehensive income (loss)	$	(1,873	)	$	1,512	$	—	$	2

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


December 31, 2008	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Minimum pension liability	$	(224	)	$	—		$	—		$	—
Adjustment to initially apply SFAS No. 158(a)		(1,268	)		2			—			—
Net unrealized gain on cash-flow hedges		564			855			—			2
Pension and non-pension postretirement benefit plans		(1,317	)		(22	)		—			—
Unrealized loss on marketable securities		(6	)		—			(5	)		—

Total accumulated other comprehensive income (loss)	$	(2,251	)	$	835		$	(5	)	$	2

(a)	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132-R”

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

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

Three Months Ended June 30, 2009 and 2008

Exelon’s segment information for the three months ended June 30, 2009 and 2008 is as follows:


	Generation		ComEd		PECO		Other			Intersegment Eliminations			Consolidated
Total revenues(a):
2009	$	2,378	$	1,389	$	1,204	$	207		$	(1,037	)	$	4,141
2008		2,756		1,425		1,277		176			(1,012	)		4,622
Intersegment revenues(b):
2009	$	833	$	—	$	2	$	207		$	(1,036	)	$	6
2008		834		—		2		176			(1,012	)		—
Income (loss) from continuing operations before income taxes:
2009	$	867	$	189	$	102	$	(70	)	$	—		$	1,088
2008		1,036		56		83		(34	)		27			1,168
Income taxes:
2009	$	355	$	73	$	31	$	(36	)	$	7		$	430
2008		383		21		25		(21	)		11			419
Income (loss) from continuing operations:
2009	$	512	$	116	$	71	$	(34	)	$	(7	)	$	658
2008		653		35		58		(13	)		16			749
Income (loss) from discontinued operations:
2009	$	—	$	—	$	—	$	(1	)	$	—		$	(1	)
2008		—		—		—		(1	)		—			(1	)
Net income (loss):
2009	$	512	$	116	$	71	$	(35	)	$	(7	)	$	657
2008		653		35		58		(14	)		16			748
Total assets:
June 30, 2009	$	22,125	$	20,007	$	9,107	$	5,882		$	(8,142	)	$	48,979
December 31, 2008		20,355		19,237		9,169		5,992			(6,936	)		47,817

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(a)

For the three months ended June 30, 2009 and 2008, utility taxes of $42 million and $55 million, respectively, are included in revenues and expenses for ComEd. For the three months ended June 30, 2009 and 2008, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for PECO.

(b)

The intersegment profit associated with Generation’s sale of RECs to ComEd and AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” See Note 3 — Regulatory Issues for additional information on RECs and AECs.

Six Months Ended June 30, 2009 and 2008

Exelon’s segment information for the six months ended June 30, 2009 and 2008 is as follows:


	Generation			ComEd		PECO		Other			Intersegment Eliminations			Consolidated
Total revenues(a):
2009	$	4,979		$	2,942	$	2,718	$	391		$	(2,167	)	$	8,863
2008		5,238			2,865		2,754		348			(2,066	)		9,139
Intersegment revenues(b):
2009	$	1,777		$	1	$	4	$	391		$	(2,167	)	$	6
2008		1,713			—		4		347			(2,064	)		—
Income (loss) from continuing operations before income taxes:
2009	$	1,618		$	343	$	259	$	(109	)	$	(2	)	$	2,109
2008		1,675			123		224		(65	)		49			2,006
Income taxes:
2009	$	577		$	113	$	76	$	(33	)	$	7		$	740
2008		584			47		69		(43	)		19			676
Income (loss) from continuing operations:
2009	$	1,041		$	230	$	183	$	(76	)	$	(9	)	$	1,369
2008		1,091			76		155		(22	)		30			1,330
Income (loss) from discontinued operations:
2009	$	—		$	—	$	—	$	—		$	—		$	—
2008		(1	)		—		—		—			—			(1	)
Net income (loss):
2009	$	1,041		$	230	$	183	$	(76	)	$	(9	)	$	1,369
2008		1,090			76		155		(22	)		30			1,329

(a)	For the six months ended June 30, 2009 and 2008, utility taxes of $108 million are included in revenues and expenses for ComEd. For the six months ended June 30, 2009 and 2008, utility taxes of $121 million and $131 million, respectively, are included in revenues and expenses for PECO.

(b)

115

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues from affiliates
ComEd Transitional Funding Trust(a)	$	—		$	1		$	—		$	2
PETT		1			1			2			3
ComEd(b)		4			—			4			—
PECO(b)		2			—			2			—

Total operating revenues from affiliates	$	7		$	2		$	8		$	5

Fuel purchases from related parties
Keystone Fuels, LLC	$	13		$	17		$	30		$	32
Conemaugh Fuels, LLC		16			13			35			26

Total fuel purchases from related parties	$	29		$	30		$	65		$	58

Interest expense to affiliates, net
ComEd Transitional Funding Trust(a)	$	—		$	1		$	—		$	5
ComEd Financing II(c)		—			—			—			2
ComEd Financing III		3			3			7			7
PETT		14			27			32			55
PECO Trust III		2			2			3			3
PECO Trust IV		1			1			3			3
Other		1			—			(1	)		—

Total interest expense to affiliates, net	$	21		$	34		$	44		$	75

Equity in earnings (losses) of unconsolidated affiliates and investments
ComEd Funding LLC(a)	$	—		$	(3	)	$	—		$	(5	)
PETT		(6	)		(4	)		(12	)		(7	)
NuStart Energy Development, LLC		—			(1	)		(1	)		(1	)
Other		—			—			(1	)		—

Total equity in earnings (losses) of unconsolidated affiliates and investments	$	(6	)	$	(8	)	$	(14	)	$	(13	)

(a)

In the fourth quarter of 2008, ComEd fully paid its long-term debt obligations to the ComEd Transitional Funding Trust and received its current receivable from the ComEd Transitional Funding Trust. ComEd Funding LLC liquidated its investment in the ComEd Transitional Funding Trust and ComEd liquidated its investment in ComEd Funding LLC.

(b)

(c)	ComEd Financing II was liquidated and dissolved upon repayment of the debt in 2008.

116

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of June 30, 2009		As of December 31, 2008
Investments in affiliates
ComEd Financing III	$	6	$	6
PETT		17		30
PECO Energy Capital Corporation		4		4
PECO Trust IV		5		5

Total investments in affiliates	$	32	$	45

Payables to affiliates (current)
ComEd Financing III	$	4	$	4
PECO Trust III		1		1

Total payables to affiliates (current)	$	5	$	5

Long-term debt to PETT and other financing trusts (including due within one year)
ComEd Financing III	$	206	$	206
PETT		794		1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt due to financing trusts	$	1,184	$	1,514

Transactions involving Generation, ComEd, and PECO are further described in the tables below.

Generation

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Operating revenues from affiliates
ComEd(a)	$	351	$	326		$	790	$	711
PECO(b)		482		509			987		1,002
BSC (d)		—		(1	)		—		—

Total operating revenues from affiliates	$	833	$	834		$	1,777	$	1,713

Fuel expense from related parties
Keystone Fuels, LLC	$	13	$	17		$	30	$	32
Conemaugh Fuels, LLC		16		13			35		26

Total fuel purchases from related parties	$	29	$	30		$	65	$	58

117

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Operating and maintenance from affiliates
ComEd(c)	$	—	$	—		$	1	$	—
PECO(c)		2		2			4		4
BSC(d)		82		69			159		140

Total operating and maintenance from affiliates	$	84	$	71		$	164	$	144

Equity in losses of investments
NuStart Energy Development, LLC	$	—	$	(1	)	$	(1)	$	(1)

Total equity in losses of investments	$	—	$	(1	)	$	(1)	$	(1)

Cash distribution paid to member	$	396	$	302		$	675	$	991


	As of June 30, 2009		As of December 31, 2008
Mark-to-market derivative assets with affiliate (current)
ComEd(e)	$	285	$	111
Receivables from affiliates (current)
ComEd(a)(f)(g)		115		151
PECO(b)		181		126

Total receivables from affiliates (current)	$	296	$	277

Receivable from affiliate (noncurrent)
Exelon(h)	$	1	$	1
Mark-to-market derivative assets with affiliate (noncurrent)(e)	$	753	$	345
Prepaid voluntary employee beneficiary association trust
Generation(i)	$	—	$	2
Payables to affiliates (current)
Exelon(h)	$	9	$	44
BSC(d)		42		34

Total payables to affiliates (current)	$	51	$	78

Payables to affiliates (noncurrent)
ComEd decommissioning(j)	$	1,418	$	1,289
PECO decommissioning(j)		72		47

Total payables to affiliates (noncurrent)	$	1,490	$	1,336

(a)

Generation has a supplier forward contract and an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 — Regulatory Issues for additional information.

(b)

Generation has a PPA with PECO, as amended, to provide the full energy requirements to PECO through 2010. See Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for more information regarding the PPA. Generation has a five-year agreement with PECO to sell AECs. See Note 3 — Regulatory Issues for additional information.

(c)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.

118

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EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(d)	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.

(e)	Primarily represents the fair value of Generation’s five-year financial swap contract with ComEd.

(f)

Under the Illinois Settlement Legislation Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued though ComEd. As of June 30, 2009 and December 31, 2008, Generation had a $12 million and $10 million payable, respectively, to ComEd. See Note 3 — Regulatory Issues for additional information.

(g)	As of June 30, 2009, Generation had a $35 million receivable from ComEd associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 — Regulatory Issues and Note 8 — Derivative Financial Instruments for additional information.

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

(i)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans accumulated at December 31, 2008 due to actuarially determined contribution rates, which are the basis for Generation’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(j)

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent nuclear decommissioning trust funds are greater than the underlying AROs at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual report on Form 10-K for additional information.

ComEd

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating revenues from affiliates
Generation	$	—	$	—	$	1	$	—
ComEd Transitional Funding Trust(a)		—		1		—		2

Total operating revenues from affiliates	$	—	$	1	$	1	$	2

Purchased power from affiliate
Generation(b)	$	347	$	326	$	786	$	711
Operating and maintenance from affiliate
BSC(c)	$	46	$	43	$	89	$	86
Interest expense to affiliates, net
ComEd Transitional Funding Trust(a)	$	—	$	1	$	—	$	5
ComEd Financing II(a)		—		—		—		2
ComEd Financing III		3		3		7		7

Total interest expense to affiliates, net	$	3	$	4	$	7	$	14

Equity in losses of unconsolidated affiliate
ComEd Funding LLC(a)	$	—	$	3	$	—	$	5
Capitalized costs
BSC(c)	$	19	$	15	$	31	$	27
Cash dividends paid to parent	$	60	$	—	$	120	$	—

119

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of June 30, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust(d)	$	6	$	9
Investments in affiliate(e)
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
Generation(g)	$	1,418	$	1,289
Other		2		2

Total receivable from affiliates (noncurrent)	$	1,420	$	1,291

Payables to affiliates (current)
Generation(b)(h)(i)	$	115	$	151
BSC(c)		28		22
ComEd Financing III		4		4
Other		1		2

Total payables to affiliates (current)	$	148	$	179

Mark-to-market derivative liability with affiliate (current)
Generation(f)	$	285	$	111
Mark-to-market derivative liability with affiliate (noncurrent)
Generation(f)	$	752	$	345
Long-term debt to ComEd financing trust
ComEd Financing III	$	206	$	206

(a)	In the fourth quarter of 2008, ComEd fully paid its long-term debt obligations to the ComEd Transitional Funding Trust. ComEd Financing II was liquidated and dissolved upon repayment of the debt during 2008.

(b)

ComEd procures a portion of its electricity supply requirements from Generation under a supplier forward contract and an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement. See Note 3 — Regulatory Issues and Note 8 — Derivative Financial Instruments for additional information.

(c)	ComEd 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.

(d)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

(e)	Investments in affiliates are included in other noncurrent assets.

(f)	To fulfill a requirement of the Illinois Settlement, ComEd entered into a five-year financial swap with Generation.

(g)

ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. 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.

(h)	As of June 30, 2009, ComEd had a $35 million payable to Generation associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 — Regulatory Issues and Note 8 — Derivative Financial Information for additional information.

(i)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of June 30, 2009 and December 31, 2008, ComEd had a $12 million and $10 million receivable, respectively, from Generation. See Note 3 — Regulatory Issues for additional information.

120

EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

PECO

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating revenues from affiliates
Generation(a)	$	2	$	2	$	4	$	4
PETT(b)		1		1		2		3

Total operating revenues from affiliates	$	3	$	3	$	6	$	7

Purchased power from affiliate
Generation(c)	$	480	$	509	$	984	$	1,001
Operating and maintenance from affiliates
BSC(d)	$	26	$	24	$	50	$	47
Generation		—		—		1		1

Total operating and maintenance from affiliates	$	26	$	24	$	51	$	48

Interest expense to affiliates, net
PETT	$	14	$	27	$	32	$	55
PECO Trust III		2		2		3		3
PECO Trust IV		1		1		3		3

Total interest expense to affiliates, net	$	17	$	30	$	38	$	61

Equity in losses of unconsolidated affiliates
PETT	$	6	$	4	$	12	$	7
Capitalized costs
BSC(d)	$	7	$	5	$	11	$	9
Cash dividends paid to parent	$	67	$	97	$	154	$	236
Repayment of receivable from parent	$	80	$	71	$	160	$	142

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of June 30, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust(e)	$	1	$	2
Contributions to Exelon intercompany money pool(f)	$	74	$	—
Investments in affiliates
PETT	$	17	$	30
PECO Energy Capital Corporation		4		4
PECO Trust IV		5		5

Total investments in affiliates	$	26	$	39

Receivable from affiliate (noncurrent)
Generation decommissioning(g)	$	72	$	47
Payables to affiliates (current)
Generation(c)	$	181	$	126
BSC(d)		24		16
Exelon		2		1
PECO Trust III		1		1

Total payables to affiliates (current)	$	208	$	144

Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	794	$	1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	978	$	1,308

Shareholders’ equity — receivable from parent(h)	$	340	$	500

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

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

(c)	PECO obtains all of its electric supply from Generation through 2010 under a PPA. PECO has a five-year agreement with Generation to purchase AECs. See Note 3 — Regulatory Issues for additional information on AECs.

(d)	PECO 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.

(e)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

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

(g)

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

(h)	PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled by December 31, 2010.

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

18. Subsequent Events (Exelon and PECO)

On July 17, 2009, the City of Philadelphia informed Pennsylvania lawmakers that, due to the State budget impasse, the City is forced to delay spending on anything other than employee compensation, debt service, and emergencies. This means that all payments to vendors and suppliers will be delayed until the passage of the State budget and passage of legislation authorizing an increase in the City’s sales tax and changes to its pension payments. As of July 17, 2009, PECO had approximately $16 million in outstanding receivables due from the City of Philadelphia. As this is currently anticipated to solely be a delay in receiving payment from the City, PECO has not increased its allowance for doubtful accounts associated with this matter at this time.

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Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

EXELON CORPORATION

General

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

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Exelon Generation Company, LLC (Generation), whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.

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Commonwealth Edison Company (ComEd), whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in northern Illinois, including the City of Chicago.

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PECO Energy Company (PECO), whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

See Note 16 of the Combined Notes to Consolidated Financial Statements for segment information.

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

Executive Overview

Financial Results. Exelon’s net income was $657 million for the three months ended June 30, 2009, as compared to $748 million for the three months ended June 30, 2008, and diluted earnings per average common share were $0.99 for the three months ended June 30, 2009, as compared to $1.13 for the three months ended June 30, 2008.

Exelon’s net income was $1,369 million for the six months ended June 30, 2009, as compared to $1,329 million for the six months ended June 30, 2008, and diluted earnings per average common share were $2.07 for the six months ended June 30, 2009, as compared to $2.01 for the six months ended June 30, 2008.

The decrease in net income for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 was primarily due to the following:

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Lower energy gross margins at Generation due largely to revenue from certain long options in Generation’s proprietary trading portfolio in 2008, the impact of gains related to the settlement of uranium supply agreements in 2008, unfavorable portfolio and market conditions and higher nuclear fuel costs;

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net mark-to-market losses in 2009 and gains in 2008 on economic hedging activities;

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increased depreciation and amortization expense due to increased scheduled competitive transition charge (CTC) amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures; and

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increased operating and maintenance expense related to increased pension and non-pension postretirement benefit costs in 2009 resulting from lower than expected asset returns in 2008, inflation related to labor, contracting and materials expenses and costs incurred for employee severance;

Partially offset by:

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increased electric distribution revenue at ComEd and gas distribution revenue at PECO in 2009 resulting from 2008 distribution rate case orders;

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unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments; and

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the non-cash impacts in 2009 of tax uncertainty remeasurements and the reassessment of state deferred income taxes.

The increase in net income for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 was primarily due to the following:

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increased electric distribution revenue at ComEd and gas distribution revenue at PECO in 2009 resulting from 2008 distribution rate case orders;

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unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments;

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benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to Exelon and treating electricity as tangible personal property;

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the non-cash impacts in 2009 of tax uncertainty remeasurements and the reassessment of state deferred income taxes; and

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decreased operating and maintenance expense related to Exelon’s ongoing cost savings initiative, decreased allowance for uncollectible accounts expense at PECO and decreased nuclear refueling outage costs associated with a lower number of planned refueling outage days during 2009 as compared to 2008;

Partially offset by:

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the 2009 impairment of certain of Generation’s Texas plants;

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net mark-to-market gains on economic hedging activities in 2008; and

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increased depreciation and amortization expense due to increased scheduled CTC amortization at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

See Exelon Corporation — Results of Operations for further information regarding the changes in net income.

Economic Environment. As the economic environment remains challenging, the Registrants have continued to perform assessments to determine the impact, if any, of market developments, including the bankruptcy, restructuring or merging of certain financial and energy companies, on the Registrants’ financial statements. The Registrants’ assessments have included a review of macroeconomic conditions, access to liquidity in the capital and credit markets, counterparty creditworthiness, value of the Registrants’ investments (particularly in the employee benefit plans and nuclear decommissioning trust funds) and exposure to other risks. The unprecedented volatility in the economy may create additional risks in the upcoming months and possibly years.

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Macroeconomic conditions

The U.S. and global economic recession continued through the second quarter of 2009. Central banks have supported their respective financial systems by increasing liquidity, and governments have increased spending to

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stimulate economic growth. While financial markets have begun to stabilize and credit spreads have narrowed, there is only preliminary data showing manufacturing, and job losses have slowed their rate of decline. Although signs of stabilization are encouraging, growth forecasts remain negative with positive economic growth not expected until the first half of 2010.

A weak domestic economy has sharply decreased U.S. energy demand and prices. A fundamentally oversupplied natural gas market has resulted in prices below $4 per million British Thermal Units, the lowest price since 2002. U.S. coal use is down year-over-year as demand from power generation and exports remain low. Eastern coal prices are currently trading below $50 per ton after reaching more than $140 per ton last spring.

Exelon has been challenged by current economic conditions as electricity demand has been low in the ComEd and PECO service territories. In addition to weak demand, bill collection has become more difficult as customers may have less ability to pay, or may delay payment. Management has taken steps to mitigate this risk through heightened collection efforts. Additionally, lower demand for electricity may lead to lower margins for Exelon’s wholesale generation fleet. While Exelon’s hedging policies have helped protect Exelon’s earnings as markets have declined, prolonged depressed electricity prices would adversely impact Exelon’s and Generation’s results of operations in the future.

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Liquidity in the capital and credit markets

The Registrants believe they have sufficient liquidity despite the continuing challenges of the capital and credit markets. The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flow from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities ($7.3 billion in aggregate total commitments with $6.8 billion available as of June 30, 2009, of which no financial institution has more than 10% of the aggregate commitments for Exelon, Generation and PECO and 12% for ComEd). Generation also has additional letter of credit facilities used solely to enhance tax-exempt variable rate debt. Approximately $307 million of these letters of credit will expire in the third quarter of 2009. Generation plans to remarket certain of this tax-exempt debt as unenhanced with different interest rate terms and refinance the remainder with new unenhanced tax-exempt bonds. See “Variable-Rate Debt” within Liquidity and Capital Resources for further detail on these credit facilities.

While not significant to the Registrants to date, the uncertainty in capital and credit markets may result in increased borrowing costs associated with short-term and long-term debt. With the exception of debt to unconsolidated financing affiliates, the Registrants have $12 million of debt at Generation maturing for the remainder of 2009 and $613 million of debt maturing in 2010 ($400 million and $213 million at Exelon Corporate and ComEd, respectively). The debt to unconsolidated financing affiliates at PECO is repaid through the collection of competitive transition charges from customers as allowed by restructuring legislation that was adopted in Pennsylvania in 1996.

The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. Management continues to closely monitor events and the financial institutions associated with its credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. Risk Factors of Exelon’s 2008 Annual Report on Form 10-K for information regarding the effects of longer-term uncertainty in the capital and credit markets or significant bank failures.

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Counterparty creditworthiness

The Registrants are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted

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commodities or services at the contracted price. Generation’s power-marketing activities are governed by risk management policies limiting transactions to a diversified group of high quality counterparties. During 2008, the bankruptcy of Lehman Brothers Holdings Inc. and the weakening of companies within the energy industry have underscored the importance of these risk management practices. Although Generation’s credit exposure was predominately with investment grade companies at June 30, 2009, changes in forward market prices could have a disproportionate impact to the percentage of credit exposure with non-investment grade companies. As of June 30, 2009, the net exposure after credit collateral for Generation’s commodity contracts of $1,073 million included $1,046 million of exposure to investment-grade companies and $27 million of exposure to non-investment grade companies, primarily in the coal supply industry. See “Competitive Markets” below for a discussion regarding risks, including prices, associated with Generation’s uranium concentrate contracts. Management continues to closely monitor the status of Generation’s counterparties and will take action, as appropriate, to further manage its counterparty credit risk.

Under the Illinois Settlement Legislation, ComEd procures power through supplier forward contracts, standard block energy purchases and spot market purchases. Collateral postings are required only from suppliers, including Generation, for the supplier forward contracts. Beginning in June 2009, the standard block energy purchases only require collateral postings from the suppliers, including Generation, should exposures between forward market prices and benchmark price levels exceed established unsecured credit limits outlined in the contracts. In the event the counterparties fail to perform, ComEd might be forced to purchase power through a request for proposal (RFP) process or in the spot markets at less favorable prices and credit terms. As of June 30, 2009, there was no cash collateral or letters of credit posted from suppliers to ComEd. The potential failure of energy suppliers to perform is mitigated by ComEd’s ability to recover its actual costs to procure power as stipulated in the Illinois Settlement Legislation as well as the Illinois Commerce Commission (ICC) approved procurement tariff.

PECO has counterparty credit risk related to its electricity and natural gas suppliers. Generation provides 100% of PECO’s electric energy under a purchase power agreement (PPA), which expires December 31, 2010. There are no collateral posting provisions included in the PPA with Generation. In anticipation of the expiration of the PPA, PECO has begun to procure through load following, full requirements contracts (full requirements contracts), forward energy purchase block contracts (block contracts) and spot market purchases in accordance with its Pennsylvania Public Utility Commission (PAPUC) approved default service provider program (DSP Program). The full requirement contracts and block contracts entered into on June 18, 2009 are subject to the collateral requirements in the supplier master agreements, which only require collateral postings from suppliers when PECO’s exposure between the forward price curve for energy and the initial market price is greater than the defined thresholds that include the supplier’s unsecured credit limit. As of June 30, 2009, there was no requirement to obtain collateral postings from suppliers. The price risk related to the potential failure of electric suppliers to perform is mitigated by PECO’s ability to seek recovery of its actual costs to procure electricity through the generation supply adjustment included in the DSP Program settlement. PECO procures natural gas from suppliers under both short-term and long-term contracts. PECO does not obtain collateral from suppliers under its natural gas supplier agreements. The potential failure of natural gas suppliers to perform is mitigated by PECO’s ability to seek recovery of its actual costs to procure natural gas through the PAPUC’s purchased gas cost clause, subject to PAPUC review. A further discussion of counterparty risk is included in ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.

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Value of investments (particularly in employee benefit plan trusts and nuclear decommissioning trust funds)

Pension and Postretirement Benefit Plans. Exelon sponsors defined benefit pension and postretirement benefit plans for the employees of the Registrants. The Registrants believe that the oversight of the investments held under Exelon’s employee benefit plans is rigorous and that the investment strategies are prudent. During 2008, Exelon’s unfunded status increased significantly, to $6.38 billion at December 31, 2008, primarily due to lower than expected asset returns. For financial reporting purposes, the unfunded status of the plans is updated annually, at December 31. Exelon has continued to monitor the performance of the plans during the first and

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second quarters of 2009, including the impact of the financial markets on the unfunded status of the defined benefit pension and other postretirement benefit plans. If the unfunded status of the plans increases at December 31, 2009 from the levels at December 31, 2008, expected future contributions to the plans could increase or be accelerated to earlier periods than previously estimated. Conversely, improvement in the unfunded status could have the effect of reducing expected future contributions. The U.S. Treasury Department issued guidance on March 31, 2009 that provides some relief from 2009 funding requirements. Exelon is determining whether to elect the options available under that guidance, as well as monitoring other legislative pension funding relief proposals currently being discussed. See Liquidity and Capital Resources for additional information.

Nuclear Decommissioning Trust Fund Investments. Nuclear decommissioning trust funds have been established on a unit-by-unit basis to satisfy Generation’s nuclear decommissioning obligations. Currently, Generation is making contributions only to the trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds) with respect to the former PECO units, it has no recourse to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen Energy Company, LLC (AmerGen) units) if there is a shortfall of funds necessary for decommissioning. Generation believes that its oversight of these trust funds is rigorous and the investment strategy is prudent. At June 30, 2009, approximately 50% of the funds were invested in equity and 50% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. See Note 12 of the Combined Notes to Consolidated Financial Statements for the amounts of unrealized losses on the trust funds during the three and six months ended June 30, 2009.

Nuclear Regulatory Commission (NRC) regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that the NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.

Generation’s most recent report was filed with the NRC on March 31, 2009, based on trust fund values and estimated decommissioning obligations as of December 31, 2008. The estimated decommissioning obligations for the NRC report were calculated in accordance with NRC regulations and may differ from the ARO recorded on Generation’s and Exelon’s balance sheet at December 31, 2008, primarily due to differences in assumptions regarding the decommissioning alternatives to be used and potential license renewals. In its NRC filing, Generation stated that it is evaluating the remedy to be utilized to address the underfunded status and such remedy will be in accordance with NRC regulations and guidance.

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requirement as of December 31, 2008. Over 90% of this total is attributable to Generation’s four units at Braidwood and Byron, where Generation has not yet filed for license extensions. Although the NRC does not allow for potential license extensions to be credited in calculating NRC minimum funding requirements, to the extent that license extensions are granted for these units, decommissioning funds will continue to grow for an additional 20-year period. Generation presently anticipates that it will file for license extensions for these units consistent with its ongoing business plan.

See PART I. ITEM 1A. Risk Factors of Exelon’s 2008 Annual Report on Form 10-K for information regarding the effects of a longer-term disruption in the capital and credit markets or significant bank failures.

Based on a regulatory agreement with the ICC that applies to the former ComEd nuclear generating units on a unit-by-unit basis, as long as funds held in the nuclear decommissioning trust funds exceed the total estimated decommissioning obligation, decommissioning-related activities recognized in the Consolidated Statement of Operations, including realized and unrealized income and losses of the trust funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. Should the trust funds for the former ComEd units continue to experience declines in market value such that the value of the trust funds for any unit falls below the amount of the estimated decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and the adverse impact to Exelon’s and Generation’s results of operations and financial positions could be material. At June 30, 2009, the trust fund investment values for each of the former ComEd units exceeded the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is the obligation reflected on Generation’s Consolidated Balance Sheet at June 30, 2009 calculated in accordance with FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the former ComEd nuclear generating units as a result of the ICC order.

Securities Lending Program. The Registrants engage in a securities lending program with respect to the investments within their employee benefit plan trusts and nuclear decommissioning trust funds. In connection with this program, the securities loaned are supported by collateral posted by the borrowers, which the Registrants invest in a short-term collateral fund or in assets with maturities matching, or approximating, the duration of the loan of the related securities. The Registrants bear the risk of loss with respect to their invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from current market conditions. Losses recognized by the Registrants have not been significant to date. Under its lending agreements, Exelon had a fair value of invested collateral of $268 million and $660 million as of June 30, 2009 and December 31, 2008, respectively. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further

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losses. Exelon, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Exelon in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, the Registrants may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. In the fourth quarter of 2008, the Registrants decided to end their participation in the securities lending program and have chosen to initiate a gradual withdrawal of their participation in the securities lending program in order to avoid potential losses on invested cash collateral due to the lack of liquidity in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 6 months. At December 31, 2008, Exelon had $649 million of loaned securities outstanding. At June 30, 2009, Exelon had $265 million of loaned securities outstanding under its lending agreements, representing a decrease in loaned securities outstanding since December 31, 2008 of $384 million primarily due to the return of loaned securities. Of the balance of loaned securities outstanding at June 30, 2009 (in terms of value), approximately 60% is expected to be returned by the end of 2009, with the remainder expected to be returned primarily in 2010.

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Other risks

The Registrants regularly evaluate the carrying value of their long-lived assets for impairment, including goodwill and generating plants. During the six months ended June 30, 2009, Generation recorded an impairment charge of $223 million related to its Texas plants. See Notes 4 and 6 of the Combined Notes to Consolidated Financial Statements for further information on Generation’s plant impairment. Further declines in the economic environment may impact market-related assumptions, resulting in a decrease of the estimated fair value of long-lived assets.

In addition, the Registrants have reviewed their exposure to insurance risk and have concluded that there have been no material changes related to the availability and cost of liability, property, nuclear risk, and other forms of insurance. Management continues to monitor closely events and the ratings for insurance companies associated with its insurance programs. Further declines in the market may have a significant adverse impact on the availability and cost of insurance.

Outlook for 2009 and Beyond. Several significant events may occur during the rest of 2009 and beyond, including the following:

Proposal for Acquisition of NRG

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On October 19, 2008, with authorization from Exelon’s Board of Directors, Exelon submitted a proposal to NRG to enter into a business combination with NRG under which Exelon would exchange 0.485 of a share of Exelon common stock for each share of NRG common stock. On November 12, 2008, Exelon announced an exchange offer in which Exelon, through its wholly owned subsidiary Exelon Xchange, offered to acquire all of the outstanding NRG common stock in exchange for 0.485 of a share of Exelon common stock plus cash in lieu of fractional shares, representing a total equity value of approximately $6.2 billion for NRG based on Exelon’s closing price on October 17, 2008. On July 2, 2009, Exelon increased its offer to acquire all of the outstanding NRG common stock with a higher fixed ratio of 0.545 of a share of Exelon common stock for each NRG share, representing a value of approximately $8 billion for NRG based on Exelon’s closing price on July 1, 2009. Exelon filed definitive proxy materials to solicit proxies from NRG shareholders at NRG’s annual meeting of shareholders for the expansion of the NRG board of directors and the election of nine new independent directors to the NRG board. At the NRG annual meeting on July 21, 2009, Exelon’s proposals to expand the NRG board to 19 directors and elect nine candidates to the expanded NRG board were not approved by the NRG shareholders. On July 21, 2009, Exelon announced that it had terminated efforts to acquire NRG, including the exchange offer.

Following the public announcement of Exelon’s proposal to acquire NRG, (1) Standard & Poor’s Ratings Services (S&P) lowered its corporate credit rating on Exelon, Generation and PECO to “BBB” from “BBB+” and lowered the senior unsecured ratings of Exelon to “BBB-” from “BBB” and of Generation to “BBB” from “BBB+” and of PECO’s senior secured debt to “A-” from “A”; and in addition, the ratings

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of Exelon and all of its subsidiaries, including ComEd, were placed on CreditWatch by S&P with negative implications; (2) Fitch Ratings, Ltd. (Fitch) placed Exelon and Generation on Rating Watch Negative; and (3) Moody’s Investors Service (Moody’s) placed the ratings of Exelon, Generation and PECO under review for possible downgrade.

On July 21, 2009, following Exelon’s termination of efforts to acquire NRG, Fitch affirmed Exelon’s and Generation’s current ratings and removed both Registrants from Ratings Watch Negative. Both Registrants were assigned a Stable ratings outlook. On July 22, 2009, S&P affirmed the ratings for Exelon, Generation and PECO and removed each Registrant from CreditWatch Negative. S&P also raised ComEd’s corporate credit rating to BBB from BBB-, its senior secured rating to A- from BBB+, its senior unsecured rating to BBB from BBB-, and its short-term rating to A2 from A3. S&P also removed ComEd’s ratings from CreditWatch Negative. The outlook for all ratings is Stable. On July 23, 2009, Moody’s confirmed Exelon’s and Generation’s current ratings and PECO’s long-term debt rating. The outlook for Exelon’s and Generation’s debt rating is Stable. PECO’s long-term debt rating was placed on Negative outlook and its short-term rating was downgraded to P2 from P1.

Exelon is firmly committed to maintaining investment grade ratings for the senior unsecured debt of Exelon and its subsidiaries. Based on Exelon’s understanding of the requirements to maintain investment grade ratings for the senior unsecured debt of Exelon and its subsidiaries at all the credit rating agencies and Exelon’s internal analysis, and considering Exelon’s decision to abandon its effort to acquire NRG, and the July actions of the rating agencies, Exelon expects that it will be able to retain its investment grade ratings for the foreseeable future without the need for the issuance of additional equity or asset sales. See “Security Ratings” within Liquidity and Capital Resources for additional information on developments in credit ratings following Exelon’s termination of efforts to acquire NRG.

Regulatory Matters

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Generation

On April 8, 2009, the NRC issued to Generation a renewed operating license for Oyster Creek Generating Station (Oyster Creek) that expires in April 2029, enabling Oyster Creek to operate for an additional 20 years beyond its original license period. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

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ComEd

ComEd is subject to various Federal and state regulation, and is currently involved in various regulatory approval proceedings in which various parties can intervene by submitting arguments to the regulatory agencies. The resulting outcome of these proceedings could be material. These regulatory matters include the requirements of the Illinois Settlement Legislation, transmission and distribution rate cases, procurement proceedings, and other regulatory issues. See Notes 3 and 14 of the Combined Notes to Consolidated Financial Statements for additional matters and further detail related to these proceedings.

In July 2009, comprehensive legislation has been enacted into law in Illinois which provides public utility companies the ability to bill or refund customers for the difference between the company’s annual uncollectible expense and amounts collected in rates through a rider mechanism. The legislation allows a public utility company to bill customers for under collections of uncollectible accounts starting with 2008 and prospectively. ComEd under collected approximately $26 million during 2008 and approximately $4 million during the six months ended June 30, 2009. Upon approval by the ICC of ComEd’s tariff to begin collecting past due amounts, ComEd would be required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund to assist low-income residential customers through the forgiveness of a portion of past due amounts.

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PECO and Generation

PECO is subject to various Federal and state regulation. PECO is preparing for the expiration of its electric generation rate caps and its PPA with Generation on December 31, 2010. PECO has been engaged in regulatory proceedings with the PAPUC to address its plan to transition to market-based

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electric generation rates and compliance with recently adopted Pennsylvania legislation. These regulatory proceedings include PECO’s Default Service Program (DSP Program) and Rate Mitigation Plans, Energy Efficiency and Conservation Plan and other regulatory filings. On June 18, 2009, PECO, in accordance with the PAPUC-approved DSP Program, entered into contracts with various counterparties to procure electric generation for the residential procurement class beginning in 2011. PECO will procure additional electric generation three more times before 2011 through full requirements and block contracts of varying lengths.

Although these proceedings support competitive, market-based procurement during the 29-month term of the approved DSP Program, elected officials in Pennsylvania have suggested rate-cap extensions, rate-increase deferrals and phase-ins, a generation tax and contributions of value (potentially billions of dollars statewide) by Pennsylvania utility companies toward rate relief programs that could have a significant impact on PECO and Generation. The outcome or settlement of these matters or any other legislative actions taken could have a material effect on PECO’s and Generation’s results of operations and cash flows.

The Pennsylvania Legislature is currently considering House Bill No. 80 (HB 80), which, if enacted into law, would increase the minimum required percentage of electric energy from alternative energy resources, expand the solar purchase and sale requirements and would incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource.

See Note 3 of the Combined Notes to Consolidated Financial Statements for further detail related to these matters.

Environmental Legislation

•

On June 26, 2009, the U.S. House of Representatives passed H.R. 2454. Among its various components, the legislation proposes mandatory, economy-wide greenhouse gas (GHG) reduction targets and goals that would be achieved via a Federal emissions cap-and-trade program. Regulation under a cap-and-trade program of carbon dioxide (CO₂) emissions from fossil generation is expected to increase wholesale power prices because generating units would seek to recover their cost of compliance with carbon regulation. Due to its overall low-carbon generation portfolio, Exelon expects to have an advantage over fossil fuel powered generation under a cap-and-trade program. Exelon has estimated that its revenue during the first year of compliance after enactment of H.R. 2454, as currently drafted, could increase by approximately $1.1 billion, assuming $15/tonne CO₂ allowance price and other assumptions, including but not limited to, merchant coal allocations. Exelon’s estimate is based on only one of several potential outcomes of the legislation and is not a forecast for the impact of any proposed or enacted legislation on its results of operations, cash flows and financial position. Exelon supported the passage of H.R. 2454 in the House of Representatives and views the legislation as balancing the need to protect consumers, business and the economy with the urgent need to reduce the emissions of GHGs in the United States. The Senate is expected to consider its own version of the legislation sometime later in 2009 or in 2010. Exelon supports the passage of comprehensive climate change legislation during the current Congressional session. Any legislation passed by the Senate would need to be reconciled with H.R. 2454 and signed by President Obama before legislation would become law.

•

Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its greenhouse gas (GHG) emissions by 8% from 2001 levels by the end of 2008. As of December 31, 2008, Exelon had achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the previous closure of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and its current energy efficiency initiatives. On March 12, 2009, Exelon submitted its final GHG inventory documentation, including a third-party verification report, to the EPA for final agency review. On April 6, 2009, the EPA notified Exelon that it had reviewed the documents submitted and confirmed that Exelon had exceeded its voluntary goal. Based on its verified GHG emissions inventory, Exelon’s 2008 carbon dioxide-equivalent (CO₂-e) emissions were 9.7 million metric tons. Compared to its 2001 baseline of 15.7 million metric tons of CO₂-e emissions, Exelon achieved a reduction of nearly 6.0 million metric tons (a 38% reduction below baseline) at the end of 2008. The cost

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of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s future competitive position, results of operations, earnings, financial position or cash flows. See Note 14 of the Combined Notes to consolidated Financial Statements for further discussion of Exelon’s voluntary greenhouse gas emission reductions.

•

The Registrants are subject to regulation regarding environmental matters, including air, water and noise emissions and solid waste disposals, by Federal, state, and local jurisdictions where the Registrants operate their facilities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures. The Registrants’ operations have in the past and may in the future require substantial expenditures in order to comply with these regulations. See Note 14 of the Combined Notes to Consolidated Financial Statements for further discussion on environmental matters, including the impacts of the Clean Air Interstate Rule, Section 316(b) of the Clean Water Act, the Clean Air Act and H.R. 2454.

Potential and New Legislation

•

Due to the new Democratic Administration and increased Democratic majorities in the U.S. House of Representatives and U.S. Senate, there is a stronger likelihood that legislation related to energy, environmental and tax policy will be enacted in the foreseeable future. These changes may include, but are not limited to, legislation or regulation limiting greenhouse gas emissions and implementation of a renewable electricity standard, such H.R. 2454 as discussed further in Note 14 of the Combined Notes to Consolidated Financial Statements; changing corporate tax law; a higher tax on capital gains and dividend income; and incentives for investments in transmission, smart grid deployment, energy efficiency and renewable generation. Exelon continuously evaluates the potential impact of proposed public policy changes that may impact the Registrants either favorably or unfavorably.

Liquidity and Cost Management

•

As noted in “Economic Environment” above, the Registrants routinely review the sufficiency of their liquidity position. Due to the national and world-wide financial crisis, uncertainty in the capital and credit markets as well as increased volatility in commodity markets may adversely affect the Registrants’ businesses, including the availability and cost of new short-term funds for liquidity requirements, their ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets. The occurrence of one or more of these events could adversely affect the Registrants’ financial condition, results of operations and cash flows (including the ability to pay dividends or fund other discretionary uses of cash such as growth projects). Given the current economic situation, Exelon anticipates that it will be subject to significant ongoing cost pressures. Exelon is committed to operating its businesses responsibly and to appropriately managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Toward that end, Exelon has launched a company-wide initiative which combines short-term actions with long-term change. In the short-term, Exelon will realize cost savings in 2009 by cutting baseline new business spend to align with decreased demand and eliminating or deferring capacity expansion projects to align with lower load projections. Additionally, in June 2009, Exelon announced the reorganization of its senior management team coupled with job reductions to enhance operating efficiencies. Taking into account job reductions, changes to the company’s compensation program and other reductions in spending across all operating companies, Exelon projects a nearly 3.5% decrease in year-over-year operations and maintenance (O&M) spending, from approximately $4.5 billion in 2009 to $4.35 billion in 2010. These reductions represent over $350 million of O&M savings in 2010, as Exelon anticipated a 4% increase in O&M absent these actions. Exelon expects over half of these cost savings to be sustainable. During the second quarter, Exelon recorded a pre-tax charge of approximately $40 million related to the announced job reductions. With regard to long-term changes, Exelon is rigorously analyzing cost trends over the past five years to identify cost savings opportunities and implementing more rigorous planning and

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performance-measurement tools that allow it to better identify areas for additional sustainable productivity improvements and cost reductions across the operating companies. Exelon is committed to an ongoing strategy to make itself more effective, efficient and innovative.

•

The Registrants’ credit facilities extend through October 2012 for Exelon, Generation and PECO and February 2011 for ComEd. These credit facilities currently provide sufficient liquidity to the Registrants. Generation is evaluating the need for additional liquidity primarily to support new collateral requirements related to hedging activities once the PPA with PECO terminates at December 31, 2010. Additionally, upon maturity of these credit facilities, the Registrants will likely not be able to renew these existing facilities at current terms or commitment levels from banks. Given this, the Registrants will likely face increased costs for liquidity needs and may be required to establish alternative liquidity sources to supply the balance of their needs beginning in 2010 for ComEd and in 2011 for Exelon, Generation, and PECO.

Competitive Markets

•

In general, market prices for energy have increased since PECO entered into its PPA with Generation due to the rise in natural gas and other fuel prices. As a result, PECO customers’ generation rates generally have been below wholesale energy market prices in PJM, and Generation’s margins on sales in excess of PECO’s requirements generally have been higher during this time. Given its significance to Generation, the expiration at the end of 2010 of the PPA with PECO could result in significant changes in margins earned by Generation beginning in 2011. Any increase or decrease in margin as a result of entering into new power supply contracts backed by the generation capacity previously committed to PECO will depend on a number of factors, including future wholesale market prices, energy demand and the outcome of Pennsylvania transition legislation.

•

Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2009 and 2010. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2009, the percentage of expected generation hedged was 95% - 98%, 87% - 90%, and 59% - 62% for 2009, 2010 and 2011, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years as well.

•

Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term contracts for uranium concentrates and through long-term contracts for conversion services, enrichment services and fuel fabrication services. Generation procures coal primarily through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2009 through 2013 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material

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adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with certain commodity price exposures.

New Growth Opportunities

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Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. Generation has been exploring the development of a new nuclear plant; however, Generation has not made a decision to build a nuclear plant at this time. In September 2008, Generation submitted a combined construction and operating license (COL) application to the NRC seeking authorization to build and operate a new dual unit nuclear generating facility in Victoria County in southeast Texas. The COL application was filed to preserve for Generation the option to develop a new nuclear plant in Texas without immediately committing to the full project. In addition, Generation filed Part I and Part II of a loan guarantee application with the Department of Energy (DOE) for these potential new units in September 2008 and December 2008, respectively, which was updated in March 2009 to reflect the selection of an alternate reactor technology. As a result of uncertainties in the domestic economy, the limited availability of Federal loan guarantees and related economic considerations, Generation announced on June 30, 2009, that it will seek an Early Site Permit (ESP) for its proposed new nuclear plant site rather than a COL. The change in licensing strategy allows Generation to continue with some aspects of site evaluation and approvals while deferring a decision on construction and technology choices for up to 20 years. The ESP submittal is scheduled for late 2009 or early 2010. Additionally, Generation continues to hold options for acquiring the land and water rights for the proposed site. Among the various conditions that must be resolved before any formal decision is made to build a new nuclear plant by Generation are the granting of a COL by the NRC; significant progress to resolve questions around the short-term interim and long-term permanent storage, as well as potential future recycling, of spent nuclear fuel; broad public acceptance of a new nuclear plant; and assurances that a new plant can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, including the availability of sufficient financing, production and other potential tax credits, and other key economic factors. In June 2009, Exelon and Generation approved an additional $30 million of expenditures on the project, bringing total authorized spending on the project to $130 million. Amounts spent on the project to date have been expensed.

•

On May 1, 2008, Generation announced that it is actively pursuing the development of a 600-megawatt combined-cycle natural gas power plant in Pennsylvania. The new plant would advance Exelon’s efforts to combat carbon emissions associated with electricity generation. Generation has been looking at several existing plant sites that it owns with access to the transmission lines, water and fuel needed to operate a new power plant. Generation has stated that a final decision on whether to move forward would be made only after it had more certainty around environmental permitting and had performed a more detailed economic review. Generation will continue to study the development of the project but will not make material investments or pursue permits until general market conditions have improved the estimated economic returns of the project. Amounts spent on the project to date, which are not material, have been expensed.

•

On June 12, 2009, in connection with the 38-megawatt increase in output at Generation’s Quad Cities nuclear plant in Illinois, Generation announced a series of planned power uprates across its nuclear fleet that will generate between 1,300 and 1,500 megawatts of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.5 billion, as measured in current costs. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Dresden, LaSalle and Quad-Cities plants in Illinois. Those projects are expected to produce nearly a quarter of the new megawatts. The remainder of uprate megawatts will come from additional projects across Generation’s nuclear fleet beginning in 2010 and ending in 2017. At 1,500 nuclear-generated megawatts,

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the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates have an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

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 2008 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for asset retirement obligations, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies and revenue recognition. At June 30, 2009, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2008.

New Accounting Pronouncements

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

Results of Operations — Exelon Corporation


Exelon Corporation	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
Exelon Corporation	2009			2008			Favorable (Unfavorable) Variance			2009			2008			Favorable (Unfavorable) Variance
Operating revenues	$	4,141		$	4,622		$	(481	)	$	8,863		$	9,139		$	(276	)
Operating expenses
Purchased power and fuel expense		1,381			1,518			137			2,840			3,129			289
Operating and maintenance expense		1,110			1,080			(30	)		2,472			2,273			(199	)
Operating and maintenance expense for regulatory required programs		14			6			(8	)		25			6			(19	)
Depreciation and amortization		439			402			(37	)		875			799			(76	)
Taxes other than income		180			186			6			380			379			(1	)

Total operating expenses		3,124			3,192			68			6,592			6,586			(6	)

Operating income		1,017			1,430			(413	)		2,271			2,553			(282	)

Other income and deductions
Interest expense		(159	)		(180	)		21			(323	)		(361	)		38
Interest expense to affiliates, net		(21	)		(34	)		13			(44	)		(75	)		31
Equity in losses of unconsolidated affiliates and investments		(6	)		(8	)		2			(14	)		(13	)		(1	)
Other, net		257			(40	)		297			219			(98	)		317

Total other income and deductions		71			(262	)		333			(162	)		(547	)		385

Income from continuing operations before income taxes		1,088			1,168			(80	)		2,109			2,006			103
Income taxes		430			419			(11	)		740			676			(64	)

Income from continuing operations		658			749			(91	)		1,369			1,330			39
Income from discontinued operations, net of income taxes		(1	)		(1	)		—			—			(1	)		1

Net income	$	657		$	748		$	(91	)	$	1,369		$	1,329		$	40

Diluted earnings per share	$	0.99		$	1.13		$	(0.14	)	$	2.07		$	2.01		$	0.06

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Net Income.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Exelon’s net income for the three months ended June 30, 2009 decreased primarily due to lower energy gross margins at Generation largely due to revenue in 2008 from certain long options in Generation’s proprietary trading portfolio, the impact of mark-to-market losses in 2009 and gains in 2008 on economic hedging activities, the impact of gains related to the settlement of uranium supply agreements in 2008 and unfavorable portfolio and market conditions; reduced load at ComEd and PECO; the impact of unfavorable 2009 weather conditions in the PECO service territory; increased pension and non-pension postretirement benefit costs in 2009 resulting from lower than expected asset returns in 2008; inflation related to labor, contracting and materials expenses; costs incurred for employee severance; and increased depreciation and amortization expense due to scheduled CTC amortization expense at PECO and increased depreciation across the operating companies due to ongoing capital expenditures. These decreases were partially offset by increased distribution revenue at ComEd resulting from its September 2008 distribution rate case order; increased gas distribution rates at PECO effective January 1, 2009; Exelon’s ongoing cost savings initiative, decreased 2009 allowance for uncollectible accounts expense at PECO; lower costs associated with the 2007 Illinois electric rate settlement agreement; the impact of decreased storm costs in 2009 in the ComEd and PECO service territories; unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments; increased interest income associated with the remeasurement of uncertain income tax positions; the benefit from a reassessment of state deferred income taxes; and decreased interest expense.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Exelon’s net income for the six months ended June 30, 2009 increased primarily due to favorable portfolio and market conditions; increased nuclear output as a result of fewer refueling outage days in 2009; lower costs associated with the 2007 Illinois electric rate settlement agreement; increased distribution revenue at ComEd resulting from its September 2008 distribution rate case order; increased gas distribution rates at PECO effective January 1, 2009; Exelon’s ongoing cost savings initiative; decreased 2009 allowance for uncollectible accounts expense at PECO; decreased expenses related to a lower number of planned nuclear refueling outages; the impact of decreased storm costs in 2009 in the ComEd and PECO service territories; benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to Exelon; unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments; increased interest income associated with the remeasurement of uncertain income tax positions; the benefit from a reassessment of state deferred income taxes; the impact of lower PECO electric distribution rates in 2008 due to the refund of the 2007 Public Utility Realty Tax Act (PURTA) settlement to customers; and decreased interest expense. These increases were partially offset by revenue in 2008 from certain long options in Generation’s proprietary trading portfolio; mark-to-market gains in 2008 on economic hedging activities; the impact of gains related to the settlement of uranium supply agreements in 2008; reduced load at ComEd and PECO; increased nuclear fuel costs at Generation; the 2009 impairment of certain of Generation’s Texas plants; increased pension and non-pension postretirement benefit costs in 2009 resulting from lower than expected asset returns in 2008; inflation related to labor, contracting and materials expenses; costs incurred for employee severance; and increased depreciation and amortization expense due to scheduled CTC amortization expense at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

Operating Revenues.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Operating revenues decreased due to the impacts of revenue in 2008 from certain long options in Generation’s proprietary trading portfolio; unfavorable portfolio and market conditions; reduced load at ComEd and PECO; the impact of unfavorable 2009 weather conditions in the PECO service territory; and lower PAPUC-approved rates charged to PECO customers for natural gas. These decreases were partially offset by increased distribution revenue at ComEd resulting from its September 2008 distribution rate case order; increased gas distribution rates at PECO effective January 1, 2009; and lower costs associated with the 2007 Illinois electric rate settlement agreement. See further analysis and discussion of operating revenues by segment below.

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Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Operating revenues decreased due to the impacts of revenue in 2008 from certain long options in Generation’s proprietary trading portfolio; reduced load at ComEd and PECO; and lower PAPUC-approved rates charged to PECO customers for natural gas. These decreases were partially offset by favorable portfolio and market conditions; increased nuclear output as a result of fewer refueling outage days in 2009; increased distribution revenue at ComEd resulting from its September 2008 distribution rate case order; the impact of lower PECO electric distribution rates in 2008 due to the refund of the 2007 PURTA settlement to customers; increased gas distribution rates at PECO effective January 1, 2009; and lower costs associated with the 2007 Illinois electric rate settlement agreement. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Purchased power and fuel expense decreased due to reduced load at ComEd and PECO, the impact of unfavorable 2009 weather conditions in the PECO service territory and lower realized natural gas prices at PECO partially offset by mark-to-market losses in 2009 and gains in 2008 on economic hedging activities, increased nuclear fuel costs at Generation, the impact of the gains related to the settlement of uranium supply agreements in 2008 and unfavorable portfolio and market conditions. See further analysis and discussion of purchased power and fuel expense by segment below.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Purchased power and fuel expense decreased due to favorable portfolio and market conditions, reduced load at ComEd and PECO and lower realized natural gas prices at PECO, partially offset by and mark-to-market gains on economic hedging activities in 2008, increased nuclear fuel costs at Generation and the impact of the gains related to the settlement of uranium supply agreements in 2008. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Operating and maintenance expense increased primarily due to increased pension and non-pension postretirement benefit costs in 2009 resulting from lower than expected asset returns in 2008, inflation related to labor, contracting and materials expenses and costs incurred for employee severance, partially offset by Exelon’s ongoing cost savings initiative, lower planned outage costs at Generation’s non-nuclear generating plants, decreased 2009 allowance for uncollectible accounts expense at PECO due to the impact of improved accounts receivable aging resulting from increased collection activities initiated in 2008 and the impact of decreased storm costs in 2009 in the ComEd and PECO service territories. See further discussion of operating and maintenance expenses by segment below.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Operating and maintenance expense increased primarily due to the 2009 impairment of certain of Generation’s Texas plants, increased pension and non-pension postretirement benefit costs in 2009 resulting from lower than expected asset returns in 2008, inflation related to labor, contracting and materials expenses and costs incurred for employee severance, partially offset by Exelon’s ongoing cost savings initiative, decreased expenses related to a lower number of planned nuclear refueling outages, lower planned outage costs at Generation’s non-nuclear generating plants, decreased 2009 allowance for uncollectible accounts expense at PECO due to the impact of improved accounts receivable aging resulting from increased collection activities initiated in 2008, and the impact of decreased storm costs in 2009 in the ComEd and PECO service territories. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense.

Three Months and Six Months Ended June 30, 2009 Compared to Three Months and Six Months Ended June 30, 2008. Depreciation and amortization expense increased primarily due to increased scheduled CTC amortization expense at PECO and increased depreciation across the operating companies due to ongoing capital expenditures.

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Taxes Other Than Income.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Taxes other than income decreased primarily due to an Illinois distribution tax refund received in 2009.

Interest Expense.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Interest expense decreased primarily due to lower interest rates on Generation’s spent nuclear fuel obligation and a lower principal balance on PECO’s outstanding debt due to PECO Energy Transition Trust (PETT).

During the three months ended June 30, 2009 and 2008, Exelon’s total interest incurred was $192 million and $225 million, respectively, including capitalized interest of $12 million and $10 million, respectively.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Interest expense decreased primarily due to lower interest rates on Generation’s spent nuclear fuel obligation, the impact of the January 2008 FERC order granting incentive treatment on a significant ComEd transmission project which reversed the previously recognized allowance for funds used during construction, and a lower principal balance on PECO’s outstanding debt due to PETT.

During the six months ended June 30, 2009 and 2008, Exelon’s total interest incurred was $392 million and $451 million, respectively, including capitalized interest of $25 million and $15 million, respectively.

Other, Net.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The increase in other, net primarily reflects the impact of unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments primarily related to Generation’s former AmerGen units and increased interest income associated with the 2009 remeasurement of uncertain income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The increase in other, net primarily reflects the impact of unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust fund investments primarily related to Generation’s former AmerGen units, benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to Exelon and increased interest income associated with the 2009 remeasurement of uncertain income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets.

Effective Income Tax Rate.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Exelon’s effective income tax rate from continuing operations for the three months ended June 30, 2009 was 39.5%, as compared to 35.9% for the three months ended June 30, 2008. The increase was primarily attributable to gains generated in the nuclear decommissioning trust funds that are taxed at a higher statutory rate than remaining income from operations. The increase was partially offset by a reduction in state income tax expenses related to a deferred state tax rate change.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Exelon’s effective income tax rate from continuing operations for the six months ended June 30, 2009 was 35.1%, as compared to 33.7% for the six months ended June 30, 2008. The increase was primarily attributable to gains generated in the nuclear decommissioning trust funds that are taxed at a higher statutory rate than remaining income from operations. The increase was partially offset by a reduction in state income tax expenses related to a deferred state tax rate change, the recognition of Illinois Investment Tax Credits and the reduction of state income taxes in

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Illinois caused by treating electricity as tangible personal property. On July 15, 2009, the Illinois Supreme Court changed its opinion related to this decision to indicate the treatment of electricity as tangible personal property will be applied only prospectively. Unless the Supreme Court changes its position again, Exelon, Generation, and ComEd will record a charge in the third quarter to reverse income previously recognized. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the three and six months ended June 30, 2009 compared to the same period in 2008 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Income (Loss) from Continuing Operations by Business Segment


	Three Months Ended June 30,					Favorable (Unfavorable) Variance			Six Months Ended June 30,					Favorable (Unfavorable) Variance
	2009			2008		Favorable (Unfavorable) Variance			2009			2008		Favorable (Unfavorable) Variance
Generation	$	512		$	653	$	(141	)	$	1,041		$	1,091	$	(50	)
ComEd		116			35		81			230			76		154
PECO		71			58		13			183			155		28
Other		(41	)		3		(44	)		(85	)		8		(93	)

Total	$	658		$	749	$	(91	)	$	1,369		$	1,330	$	39

Net Income (Loss) by Business Segment


	Three Months Ended June 30,					Favorable (Unfavorable) Variance			Six Months Ended June 30,					Favorable (Unfavorable) Variance
	2009			2008		Favorable (Unfavorable) Variance			2009			2008		Favorable (Unfavorable) Variance
Generation	$	512		$	653	$	(141	)	$	1,041		$	1,090	$	(49	)
ComEd		116			35		81			230			76		154
PECO		71			58		13			183			155		28
Other		(42	)		2		(44	)		(85	)		8		(93	)

Total	$	657		$	748	$	(91	)	$	1,369		$	1,329	$	40

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Results of Operations — Generation


	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2009			2008			Favorable (Unfavorable) Variance			2009			2008			Favorable (Unfavorable) Variance
Operating revenues	$	2,378		$	2,756		$	(378	)	$	4,979		$	5,238		$	(259	)
Operating expenses
Purchased power and fuel		891			883			(8	)		1,575			1,718			143
Operating and maintenance		689			615			(74	)		1,617			1,399			(218	)
Depreciation and amortization		72			73			1			149			143			(6	)
Taxes other than income		50			47			(3	)		100			100			—

Total operating expenses		1,702			1,618			(84	)		3,441			3,360			(81	)

Operating income		676			1,138			(462	)		1,538			1,878			(340	)

Other income and deductions
Interest expense		(24	)		(38	)		14			(52	)		(74	)		22
Equity in losses of investments		—			(1	)		1			(1	)		(1	)		—
Other, net		215			(63	)		278			133			(128	)		261

Total other income and deductions		191			(102	)		293			80			(203	)		283

Income from continuing operations before income taxes		867			1,036			(169	)		1,618			1,675			(57	)
Income taxes		355			383			28			577			584			7

Income from continuing operations		512			653			(141	)		1,041			1,091			(50	)
Loss from discontinued operations, net of income taxes		—			—			—			—			(1	)		1

Net income	$	512		$	653		$	(141	)	$	1,041		$	1,090		$	(49	)

Net Income. Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Generation’s net income for the three months ended June 30, 2009 decreased compared to the same period in 2008 primarily due to lower operating revenues, net of purchased power and fuel expense, and higher operating and maintenance expenses, partially offset by unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust funds. Lower operating revenues, net of purchased power and fuel expense, were largely due to mark-to-market losses in 2009 and gains in 2008 on economic hedging activities, revenue from certain long options in Generation’s proprietary trading portfolio in 2008, gains related to the settlement of uranium supply agreements in 2008, unfavorable portfolio and market conditions, and higher nuclear fuel costs, partially offset by lower costs associated with the 2007 Illinois electric rate settlement agreement. Higher operating and maintenance expenses primarily reflected increased decommissioning-related activities related primarily to the contractual elimination of income taxes, increased pension and non-pension post retirement benefits expense, severance charges and increased nuclear refueling outage costs associated with a higher number of planned refueling outage days during 2009 as compared to 2008.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Generation’s net income for the six months ended June 30, 2009 decreased compared to the same period in 2008 primarily due to lower operating revenues, net of purchased power and fuel expense, and the impairment of certain generating assets in 2009, partially offset by unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust funds. Lower operating revenues, net of purchased power and fuel expense, were largely due to mark-to-market gains on economic hedging activities in 2008, revenue from certain long options in

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Generation’s proprietary trading portfolio in 2008, gains related to the settlement of uranium supply agreements in 2008 and increased nuclear fuel costs, partially offset by favorable portfolio and market conditions, increased nuclear output as a result of fewer refueling outage days in 2009 and lower costs associated with the 2007 Illinois electric rate settlement agreement.

Operating Revenues. For the three months ended June 30, 2009 and 2008, Generation’s sales were as follows:


Revenue	Three Months Ended June 30,						Variance			% Change
Revenue	2009			2008			Variance			% Change
Electric sales to affiliates	$	833		$	834		$	(1	)	(0.1	)%
Wholesale and retail electric sales		1,515			1,776			(261	)	(14.7	)%

Total electric sales revenue		2,348			2,610			(262	)	(10.0	)%
Retail gas sales		46			114			(68	)	(59.6	)%
Trading portfolio		3			82			(79	)	n.m.
Other revenue(a)		(19	)		(50	)		31		62.0	%

Total operating revenue	$	2,378		$	2,756		$	(378	)	(13.7	)%

(a)	Includes amounts incurred for the Illinois Settlement, revenues relating to net fossil fuel sales and decommissioning revenue from PECO during 2009 and 2008.

n.m. Not meaningful

For the six months ended June 30, 2009 and 2008, Generation’s sales were as follows:


Revenue	Six Months Ended June 30,						Variance			% Change
Revenue	2009			2008			Variance			% Change
Electric sales to affiliates	$	1,777		$	1,713		$	64		3.7	%
Wholesale and retail electric sales		3,049			3,227			(178	)	(5.5	)%

Total electric sales revenue		4,826			4,940			(114	)	(2.3	)%
Retail gas sales		187			303			(116	)	(38.3	)%
Trading portfolio		3			103			(100	)	n.m.
Other revenue(a)		(37	)		(108	)		71		65.7	%

Total operating revenue	$	4,979		$	5,238		$	(259	)	(4.9	)%

(a)	Includes amounts incurred for the Illinois Settlement, revenues relating to fossil fuel sales and decommissioning revenue from PECO during 2009 and 2008.

n.m. Not meaningful


Sales (in gigawatt hours (GWhs)	Three Months Ended June 30,		Variance		% Change
Sales (in gigawatt hours (GWhs)	2009	2008	Variance		% Change
Electric sales to affiliates	13,701	14,979	(1,278	)	(8.5	)%
Wholesale and retail electric sales	29,271	28,575	696		2.4	%

Total electric sales	42,972	43,554	(582	)	(1.3	)%

Trading volumes of 2,003 GWhs and 1,784 GWhs for the three months ended June 30, 2009 and 2008, respectively, are not included in the table above.

142


Sales (in gigawatt hours (GWhs)	Six Months Ended June 30,		Variance		% Change
Sales (in gigawatt hours (GWhs)	2009	2008	Variance		% Change
Electric sales to affiliates	30,359	31,183	(824	)	(2.6	)%
Wholesale and retail electric sales	56,837	53,945	2,892		5.4	%

Total electric sales	87,196	85,128	2,068		2.4	%

Trading volumes of 4,334 GWhs and 3,646 GWhs for the six months ended June 30, 2009 and 2008, respectively, are not included in the table above.

Electric sales to affiliates. The changes in Generation’s electric sales to affiliates for the three and six months ended June 30, 2009 consisted of the following:


Electric sales to affiliates	Three Months Ended June 30,									Six Months Ended June 30,
Electric sales to affiliates	Price			Volume			Increase (Decrease)			Price		Volume			Increase (Decrease)
ComEd	$	75		$	(50	)	$	25		$	107	$	(28	)	$	79
PECO		(1	)		(25	)		(26	)		4		(19	)		(15	)

Total	$	74		$	(75	)	$	(1	)	$	111	$	(47	)	$	64

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The price variance in the ComEd territories was primarily related to $69 million of revenue recorded from settlements related to the ComEd swap during 2009, which started settling in June 2008. The volume decrease in the ComEd territories was due primarily to the expiration of certain tranches served under the auction contract, effective May 31, 2009, in addition to unfavorable weather, partially offset by deliveries to ComEd under the RFP, which started in September 2008. In the PECO territories, the decrease in price reflects an unfavorable change in the mix of average pricing related to PECO’s PPA with Generation. The volume decrease in the PECO territories was primarily due to unfavorable weather conditions.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The price variance in the ComEd territories was primarily related to $100 million of revenue recorded from settlements related to the ComEd swap during 2009, which started settling in June 2008. The volume decrease in the ComEd territories was due primarily to the expiration of certain tranches served under the auction contract, effective May 31, 2009, in addition to unfavorable weather, partially offset by deliveries to ComEd under the RFP, which started in September 2008. The volume decrease in the PECO territories was primarily due to unfavorable weather conditions.

Wholesale and retail electric sales. The decrease in Generation’s wholesale and retail electric sales for the three and six months ended June 30, 2009, compared to the same periods in 2008, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,
	Increase (Decrease)			Increase (Decrease)
Price	$	(304	)	$	(351	)
Volume		43			173

Decrease in wholesale and retail electric sales	$	(261	)	$	(178	)

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The decrease was primarily the result of an overall decrease in market prices, partially mitigated by higher volumes of generation sold to the market as a result of a decrease in affiliate load served.

143

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The decrease was primarily the result of an overall decrease in market prices, partially mitigated by higher volumes of generation sold to the wholesale market as a result of a decrease in affiliate load served and increased nuclear generation as a result of a decrease in refueling and non-refueling outage days.

Retail gas sales. Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Retail gas sales decreased $68 million for the three months ended June 30, 2009, as compared to the same period in 2008, of which $39 million was due to lower realized prices and $29 million was due to lower volumes as a result of a decrease in demand.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Retail gas sales decreased $116 million for the six months ended June 30, 2009, as compared to the same period in 2008, of which $54 million was due to lower realized prices and $62 million was due to lower volumes as a result of a decrease in demand.

Trading Portfolio. Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008. The three and six months ended June 30, 2008 include revenue recorded in 2008 from certain long options in the proprietary trading portfolio.

Other revenue. Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008. The increase in other revenues for the three months ended June 30, 2009 compared to the same period in 2008 was primarily due to lower costs incurred in conjunction with the Illinois Settlement.

Purchased Power and Fuel Expense. Generation’s supply sources for the three months ended June 30, 2009 and 2008 are summarized below:


Supply Source (in GWhs)	Three Months Ended June 30,		Variance		% Change
Supply Source (in GWhs)	2009	2008	Variance		% Change
Nuclear generation(a)	34,995	35,069	(74	)	(0.2	)%
Purchases — non-trading portfolio	5,276	5,575	(299	)	(5.4	)%
Fossil and hydroelectric generation	2,701	2,910	(209	)	(7.2	)%

Total supply	42,972	43,554	(582	)	(1.3	)%

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

Generation’s supply sources for the six months ended June 30, 2009 and 2008 are summarized below:


Supply Source (in GWhs)	Six Months Ended June 30,		Variance		% Change
Supply Source (in GWhs)	2009	2008	Variance		% Change
Nuclear generation(a)	70,377	68,003	2,374		3.5	%
Purchases — non-trading portfolio	11,353	11,403	(50	)	(0.4	)%
Fossil and hydroelectric generation	5,466	5,722	(256	)	(4.5	)%

Total supply	87,196	85,128	2,068		2.4	%

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

144

The following table presents changes in Generation’s purchased power and fuel expense for the three and six months ended June 30, 2009 compared to the same periods in 2008. Generation considers the aggregation of purchased power and fuel expense as a useful measure to analyze the profitability of electric operations between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with accounting principles generally accepted in the United States of America (GAAP). However, the aggregation of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information Generation provides elsewhere in this report.


	Three Months Ended June 30,									Six Months Ended June 30,
	Price			Volume			Increase (Decrease)			Price			Volume			Increase (Decrease)
Purchased power costs and tolling agreement costs	$	(232	)	$	(34	)	$	(266	)	$	(354	)	$	(5	)	$	(359	)
Generation costs		88			(1	)		87			191			11			202
Retail fuel costs		(36	)		(27	)		(63	)		(57	)		(57	)		(114	)
Mark-to-market		n.m.			n.m.			250			n.m.			n.m.			128

Increase (Decrease) in purchased power and fuel expense							$	8								$	(143	)

n.m. Not meaningful

Purchased Power Costs and Tolling Agreement Costs.

Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation incurred overall lower prices for purchased power as a result of a decline in market prices. Generation’s decreased purchased power volumes were driven primarily by market conditions that resulted in decreased purchases from contracted units.

Generation Costs.

Generation costs include fuel costs for internally generated energy.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Generation experienced overall higher generation costs primarily as a result of an increase in the cost of nuclear fuel and unfavorable hedging activity for fossil fuels. Additionally, in 2008 Generation recorded a gain of approximately $39 million related to a non-performance claim for a uranium supply agreement.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Generation experienced overall higher generation costs primarily as a result of an increase in the cost of nuclear fuel and unfavorable hedging activity for fossil fuels. The increase in volumes was primarily due to an increase in nuclear output. Additionally, in 2008 Generation recorded gains of approximately $53 million related to non-performance claims for uranium supply agreements.

Retail Fuel Costs.

Retail fuel costs include retail gas purchases.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The changes in Generation’s retail fuel costs consisted of overall lower prices resulting in a decrease of $36 million. This was in addition to lower demand resulting in a volume decrease of $27 million.

145

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The changes in Generation’s retail fuel costs consisted of overall lower prices resulting in a decrease of $57 million. This was in addition to lower demand resulting in a volume decrease of $57 million.

Mark-to-market.

Generation is exposed to market risks associated with changes in commodity prices, and enters into economic hedges to mitigate exposure to these fluctuations.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Mark-to-market losses on power hedging activities were $160 million for the three months ended June 30, 2009, including the impact of the changes in ineffectiveness, compared to losses of $46 million for the same period in 2008. Mark-to-market losses on fuel hedging activities were $13 million for the three months ended June 30, 2009 compared to gains of $123 million for the same period in 2008. See Notes 6 and 8 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives under SFAS No. 157.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Mark-to-market gains on power hedging activities were $40 million for the six months ended June 30, 2009, including the impact of the changes in ineffectiveness, compared to losses of $147 million for the same period in 2008. Mark-to-market losses on fuel hedging activities were $28 million for the six months ended June 30, 2009 compared to gains of $287 million for the same period in 2008. See Notes 6 and 8 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives under SFAS No. 157.

The following tables present average electric revenues, supply costs and margins per megawatt hours (MWh) of electricity sold during the three and six months ended June 30, 2009, as compared with the same periods in 2008. As set forth in the table, average electric margins are defined as average electric revenues less average electric supply costs. Generation considers average electric margins useful measures to analyze the change in profitability of electric operations between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these margins are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information Generation provides elsewhere in this report.


($/MWh)	Three Months Ended June 30,				% Change
($/MWh)	2009		2008		% Change
Average electric revenue
Electric sales to affiliates(a)	$	55.44	$	56.15	(1.26	)%
Wholesale and retail electric sales(a)		54.27		61.91	(12.34	)%
Total — excluding the trading portfolio		54.64		59.93	(8.83	)%
Average electric supply cost(b) — excluding the proprietary trading portfolio		15.68		19.40	(19.18	)%
Average margin — excluding the proprietary trading portfolio		38.96		40.53	(3.87	)%

(a)

For the three months ended June 30, 2009 and June 30, 2008, $69 million of pre-tax revenue and $7 million of a pre-tax reduction in revenue, respectively, from settlements related to the ComEd swap have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales. In addition, for the three months ended June 30, 2009, renewable energy credits (RECs) sales to affiliates and $7 million (209 GWhs) of pre-tax revenue from sales to ComEd under the RFP have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales. (b) Average electric supply cost includes purchased power and fuel costs associated with electric sales, excluding the impact of mark-to-market hedging activities. Average electric supply cost does not include fuel costs associated with retail gas sales and other fuel sales for all periods presented.

146


($/MWh)	Six Months Ended June 30,				% Change
($/MWh)	2009		2008		% Change
Average electric revenue
Electric sales to affiliates(a)	$	54.77	$	55.13	(0.65	)%
Wholesale and retail electric sales(a)		55.64		59.69	(6.79	)%
Total — excluding the trading portfolio		55.35		58.02	(4.60	)%
Average electric supply cost(b) — excluding the proprietary trading portfolio		16.26		18.35	(11.39	)%
Average margin — excluding the proprietary trading portfolio		39.09		39.67	(1.46	)%

(a)

For the six months ended June 30, 2009 and June 30, 2008, $100 million of pre-tax revenue and $7 million of a pre-tax reduction in revenue, respectively, from settlements related to the ComEd swap have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales. In addition, for the six months ended June 30, 2009, REC sales to affiliates and $65 million (1,107 GWhs) of pre-tax revenue from sales to ComEd under the RFP have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales.

(b)	Average electric supply cost includes purchased power and fuel costs associated with electric sales excluding the impact of mark-to-market hedging activities. Average electric supply cost does not include fuel costs associated with retail gas sales and other fuel sales for all periods presented.

The following table presents nuclear fleet operating data for the three and six months ended June 30, 2009, as compared with the same periods in 2008, for the Exelon-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one (1) MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Nuclear fleet capacity factor(a)		93.9	%		95.8	%		95.0	%		92.4	%
Nuclear fleet production cost per MWh(a)	$	15.52		$	14.47	(b)	$	15.75		$	16.35	(b)

(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC.

(b)	The three and six months ended June 30, 2008 exclude $14 million and $53 million, respectively, for the reduction in fuel expense related to uranium supply agreement non-performance settlements. See Note 14 of the Combined Notes to the Consolidated Financial Statements for further information.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The nuclear fleet capacity factor decreased primarily due to more refueling and non-refueling outage days during the three months ended June 30, 2009 compared to the same period in 2008. For the three months ended June 30, 2009 and 2008, refueling outage days totaled 57 and 40, respectively, while non-refueling outage days totaled 21 and 3, respectively. A lower number of net MWh’s generated and higher operating and maintenance costs associated with the higher number of refueling outage days resulted in a higher production cost per MWh for the three months ended June 30, 2009 as compared to the same period in 2008.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The nuclear fleet capacity factor increased primarily due to fewer refueling outage days during the six months ended June 30, 2009 compared to the same period in 2008. For the six months ended June 30, 2009 and 2008, refueling outage days

147

totaled 91 and 144, respectively, while non-refueling outage days totaled 34 and 29, respectively. A higher number of net MWh’s generated and lower operating and maintenance costs associated with the lower number of refueling outage days resulted in a lower production cost per MWh for the six months ended June 30, 2009 as compared to the same period in 2008.

Operating and Maintenance Expense. The increase in operating and maintenance expense for the three and six months ended June 30, 2009 compared to the same period in 2008, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,
	Increase (Decrease)			Increase (Decrease)
Impairment of certain generating assets	$	—		$	223
Decommissioning-related activities		45			—
Pension and non-pension post-retirement benefits expense		25			44
Severance charges		15			15
Nuclear refueling outage costs, including the co-owned Salem Plant		6			(68	)
Labor, other benefits, contracting and materials		(5	)		12
New nuclear plant development costs		(4	)		(6	)
Other		(8	)		(2	)

Increase in operating and maintenance expense	$	74		$	218

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The increase in operating and maintenance expense consisted of the following:

•

The $45 million increase in decommissioning-related activities related primarily to the contractual elimination of income taxes associated with the decommissioning trust funds of the former ComEd and PECO nuclear generating units (Regulated Units) in 2008.

•

The $25 million increase in pension and non-pension post-retirement benefits expense is primarily due to lower than expected asset returns in 2008.

•

The $15 million increase in severance charges is reflective of Exelon’s announcement in June 2009 of a reorganization of its senior management team coupled with job reductions.

•

The $6 million increase in nuclear refueling outage costs was primarily associated with a higher number of planned refueling outage days during 2009 as compared to 2008.

•

The $5 million decrease primarily reflects Exelon’s ongoing cost savings initiative and lower planned outage costs at Generation’s non-nuclear generating plants, partially offset by inflation.

•

The $4 million decrease in new nuclear plant development costs reflects a reduction in costs associated with the possible construction of a nuclear power plant in Texas.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The increase in operating and maintenance expense consisted of the following:

•

The $223 million increase relates to the impairment of certain generating assets further described in Notes 4 and 6 of the Combined Notes to Consolidated Financial Statements.

•

The $44 million increase in pension and non-pension post-retirement benefits expense is primarily due to lower than expected asset returns in 2008.

•

The $15 million increase in severance charges is reflective of Exelon’s announcement in June 2009 of a reorganization of its senior management team coupled with job reductions.

148

•

The $68 million decrease in nuclear refueling outage costs was primarily associated with a lower number of planned refueling outage days during 2009 as compared to 2008.

•

The $12 million increase in labor, other benefits, contracting and materials primarily reflects inflation, partially offset by Exelon’s ongoing cost savings initiative and lower planned outage costs at Generation’s non-nuclear generating plants.

•

The $6 million decrease in new nuclear plant development costs reflects a reduction in costs associated with the possible construction of a nuclear power plant in Texas.

Depreciation and Amortization.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Depreciation and amortization expense was relatively flat and reflected higher plant balances due to capital additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages), offset by the reassessment of the useful lives of several fossil facilities and reduced depreciation associated with the generating assets that were impaired.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The increase in depreciation and amortization expense was primarily due to higher plant balances due to capital additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages), partially offset by the reassessment of the useful lives of several fossil facilities and reduced depreciation associated with the generating assets that were impaired.

Taxes Other Than Income.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The decrease in taxes other than income was primarily due to decreased payroll taxes.

Interest Expense.

Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008. The decrease in interest expense reflected lower interest on spent nuclear fuel obligations as a result of lower rates and lower interest expense on long-term variable rate debt and commercial paper.

Other, Net.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. The increase in other, net primarily reflects the impact of unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust funds of the Unregulated Units and the contractual elimination of income taxes associated with the decommissioning trust funds of the Regulated Units, partially offset by income in 2008 related to the termination of a gas supply guarantee.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. The increase in other, net primarily reflects the impact of unrealized gains in 2009 and unrealized losses in 2008 related to nuclear decommissioning trust funds of the Unregulated Units, the contractual elimination of income taxes associated with the decommissioning trust funds of the Regulated Units and realized losses on the trust funds of the Unregulated Units due to the execution of tax planning strategy in 2008, partially offset by income in 2008 related to the termination of a gas supply guarantee.

149

The following table provides unrealized and realized losses on the decommissioning trust funds of the Unregulated Units recognized in other, net for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Net unrealized gains (losses) on decommissioning trust funds — Unregulated Units	$	115		$	(30	)	$	51		$	(99	)
Net realized (losses) on sale of decommissioning trust funds — Unregulated Units	$	(3	)	$	(6	)	$	(7	)	$	(26	)

Effective Income Tax Rate.

Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008. Generation’s effective income tax rate from continuing operations for the three and six months ended June 30, 2009 was 41.0% and 35.7%, respectively, as compared to 37.0% and 34.9% for the three and six months ended June 30, 2008. Generation’s effective tax rate for the three and six months ended June 30, 2009 increased as a result of gains generated in the nuclear decommissioning trust funds that are taxed at a higher statutory rate than Generation’s remaining income from operations. The increase for the three months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a deferred state tax rate change. The increase for the six months ended June 30, 2009 was partially offset by a reduction in state income tax expenses related to a deferred state tax rate change, the recognition of Illinois Investment Tax Credits and the reduction of state income taxes in Illinois caused by treating electricity as tangible personal property. On July 15, 2009, the Illinois Supreme Court changed its opinion related to this decision to indicate the treatment of electricity as tangible personal property will be applied only prospectively. Unless the Supreme Court changes its position again, Generation will record a charge in the third quarter to reverse income previously recognized. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information.

Results of Operations — ComEd


	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2009			2008			Favorable (Unfavorable) Variance			2009			2008			Favorable (Unfavorable) Variance
Operating revenues	$	1,389		$	1,425		$	(36	)	$	2,942		$	2,865		$	77
Purchased power expense		715			820			105			1,598			1,661			63

Revenue net of purchased power expense		674			605			69			1,344			1,204			140

Other operating expenses
Operating and maintenance		270			274			4			522			523			1
Operating and maintenance for regulatory required programs		14			6			(8	)		25			6			(19	)
Depreciation and amortization		124			113			(11	)		246			224			(22	)
Taxes other than income		57			71			14			136			140			4

Total other operating expenses		465			464			(1	)		929			893			(36	)

Operating income		209			141			68			415			311			104

Other income and deductions
Interest expense, net		(75	)		(87	)		12			(159	)		(192	)		33
Equity in losses of unconsolidated affiliates		—			(3	)		3			—			(5	)		5
Other, net		55			5			50			87			9			78

Total other income and deductions		(20	)		(85	)		65			(72	)		(188	)		116

Income before income taxes		189			56			133			343			123			220
Income taxes		73			21			(52	)		113			47			(66	)

Net income	$	116		$	35		$	81		$	230		$	76		$	154

150

Net income.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. As more fully described below, ComEd recorded higher net income for the three months ended June 30, 2009 compared to the same period in 2008 primarily as a result of increased distribution rates effective September 16, 2008, lower interest expense and higher interest income related to a remeasurement of uncertain income tax positions. This increase was partially offset by 2009 restructuring plan severance charges, higher pension and non-pension postretirement benefit costs and higher depreciation and amortization expense.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. As more fully described below, ComEd recorded higher net income for the six months ended June 30, 2009 compared to the same period in 2008 primarily as a result of increased distribution rates effective September 16, 2008, a favorable Illinois Supreme Court ruling on an income tax filing, lower interest expense and higher interest income related to a remeasurement of uncertain income tax positions. This increase was partially offset by 2009 restructuring plan severance charges, higher pension and non-pension postretirement benefit costs and higher depreciation and amortization expense.

Operating revenues and purchased power expense. ComEd evaluates its operating performance using the measure of revenue net of purchased power expense. ComEd believes revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The changes in operating revenues, purchased power expense and revenue net of purchased power expense for the three and six months ended June 30, 2009 compared to the same periods in 2008 consisted of the following:


	Three Months Ended June 30, 2009									Six Months Ended June 30, 2009
	Increase (Decrease)									Increase (Decrease)
	Operating Revenues			Purchased Power			Revenue Net of Purchased Power			Operating Revenues			Purchased Power			Revenue Net of Purchased Power
Retail energy and customer choice	$	(105	)	$	(105	)	$	—		$	(63	)	$	(63	)	$	—
Distribution pricing		67			n/a			67			137			n/a			137
Energy efficiency and demand response programs		8			n/a			8			18			n/a			18
Transmission		(1	)		n/a			(1	)		(9	)		n/a			(9	)
Volume — delivery		(12	)		n/a			(12	)		(23	)		n/a			(23	)
Weather — delivery		(2	)		n/a			(2	)		(5	)		n/a			(5	)
Franchise taxes		1			n/a			1			5			n/a			5
Other		8			n/a			8			17			n/a			17

Total increase (decrease)	$	(36	)	$	(105	)	$	69		$	77		$	(63	)	$	140

Retail energy and customer choice

Revenue. All ComEd customers have the choice to purchase electricity from an alternative electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied electricity and generation service. Customer choice does not affect ComEd’s operating income because the cost of the procured power is passed along to customers without mark-up. Revenue

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for the three and six months ended June 30, 2009 decreased primarily due to lower purchased power rates compared to the same periods in 2008, which are passed on to ComEd’s customers. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information regarding ComEd’s energy procurement process.

The following table represents customer choice for the three and six months ended June 30, 2009 compared to the same periods in 2008:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Retail customers purchasing electricity from an alternative generation electric supplier:
Number of customers at period end	48,900		41,400		48,900		41,400
Percentage of total retail customers	1	%	1	%	1	%	1	%
Volume (GWhs)	10,851		11,471		21,965		23,137
Percentage of total retail deliveries	53	%	54	%	51	%	52	%

Purchased Power. Purchased power for the three and six months ended June 30, 2009 decreased primarily due to reduced load and lower energy prices based on spot market conditions and new energy contracts effective June 1, 2009.

Distribution pricing

Revenue. Revenues for the three and six months ended June 30, 2009 increased primarily due to the 2007 Distribution Rate Case. The ICC issued an order in the 2007 Rate Case approving a $274 million increase in ComEd’s annual revenue requirement. The order became effective September 16, 2008 resulting in increased distribution revenues for the three and six months ended June 30, 2009 compared to the same periods in 2008. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

Energy efficiency and demand response programs

Revenue. As a result of the 2007 Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008 and are allowed recovery of the costs of these programs from customers on a full and current basis through a reconcilable automatic adjustment clause. During the three and six months ended June 30, 2009, ComEd recognized $13 million and $23 million of revenue associated with these programs, respectively. During the three and six months ended June 30, 2008, ComEd recognized $5 million of revenue associated with these programs, respectively. These amounts were offset by equal amounts in operating and maintenance expense for regulatory required programs. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

Transmission

Revenue. During the six months ended June 30, 2008, a FERC order approved incentive recovery treatment of ComEd’s largest transmission project. The cumulative recognition of the effects of this order resulted in higher revenues in 2008 compared to the same period in 2009. This was partially offset by the impact of the higher transmission rates effective June 1, 2008, resulting from the FERC-approved formula.

Volume — delivery

Revenue. Revenues were lower primarily resulting from a decrease in deliveries, excluding the effects of weather, due to decreased usage per customer and fewer customers for the three and six months ended June 30, 2009, compared to the same periods in 2008. ComEd believes a negative trend will continue throughout 2009.

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Weather — delivery

Revenue. Revenues were lower due to unfavorable weather conditions in the three and six months ended June 30, 2009 compared to the same periods in 2008. 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 customer usage and delivery of electricity. Conversely, mild weather reduces demand. Degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Heating degree days in ComEd’s service territory remained relatively consistent for the three and six months ended June 30, 2009 compared to the same periods in 2008. Cooling degree days in ComEd’s service territory decreased by 8% for the three and six months ended June 30, 2009 compared to the same periods in 2008.

Franchise taxes

Revenue. Revenues were higher for the three and six months ended June 30, 2009 compared to the same periods in 2008 due to increased franchise taxes. The majority of franchise taxes are based on a percentage of customers’ bills. In September 2008, customers’ bills increased due to the 2007 Distribution Rate Case resulting in a corresponding increase in franchise taxes.

Other

Revenue. Other revenues were higher for the three and six months ended June 30, 2009 compared to the same periods in 2008 due primarily to increased late payment charges and increased revenues related to assistance provided to other utilities through mutual assistance programs. Due to negative economic conditions, more customers have been delinquent in making payments resulting in higher late payment charges. Mutual assistance programs revenues increased as ComEd provided work crews to other utilities that required assistance in restoring power due to significant storms.

Operating and maintenance expense

The changes in operating and maintenance expense for the three and six months ended June 30, 2009 compared to the same periods in 2008, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,
	Increase (Decrease)			Increase (Decrease)
2009 restructuring plan severance charges	$	18		$	18
Pension and OPEB expense		13			26
Allowance for uncollectible accounts expense		5			3
Injuries and damages		(3	)		(3	)
Wages and salaries		(6	)		(9	)
Contracting		(12	)		(11	)
Storm-related costs		(13	)		(15	)
Other		(6	)		(10	)

Decrease in operating and maintenance expense	$	(4	)	$	(1	)

Operating and maintenance expense for regulatory required programs

Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. To fulfill a requirement of the Illinois Settlement, ComEd initiated the ICC approved energy efficiency

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and demand response programs beginning June 2008. During the three and six months ended June 30, 2009, expenses related to energy efficiency and demand response programs consisted of $13 million and $23 million, respectively, and $1 million and $2 million, respectively, related to purchased power administration costs. During the three and six months ended June 30, 2008, expenses related to energy efficiency and demand response programs consisted of $5 million, and $1 million related to purchased power administration costs. See Note 3 and Note 15 of the Combined Notes to the Consolidated Financial Statements for additional information.

Depreciation and amortization expense

Depreciation and amortization expense increased during the three and six months ended June 30, 2009 compared to the same period in 2008 due to higher plant balances and changes to useful lives of assets based on a depreciation rate study which became effective January 1, 2009. The change in depreciation rates is estimated to increase depreciation expense by approximately $15 million on an annual basis.

Taxes other than income

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Taxes other than income decreased for 2009 compared to 2008 primarily as a result of a $13 million refund of 2006 Illinois distribution tax received in the second quarter of 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Taxes other than income increased for 2009 compared to 2008 primarily as a result of higher revenues. The majority of taxes are based on a percentage of customers’ bills. In September 2008, customers’ bills increased due to the 2007 Distribution Rate Case resulting in a corresponding increase in taxes. ComEd received a $14 million refund of 2005 Illinois distribution tax during the first quarter of 2008, offsetting the refund received in the second quarter of 2009 discussed above.

Interest expense, net

The changes in interest expense for the three and six months ended June 30, 2009 compared to the same periods in 2008 consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,
	Increase (Decrease)			Increase (Decrease)
Interest expense related to 2008 IRS Settlement(a)	$	8		$	8
Interest expense on debt (including financing trusts)(b)		(7	)		(13	)
Interest expense related to uncertain tax positions(c)		(6	)		(13	)
FIN 48 income tax remeasurement(d)		(6	)		(6	)
AFUDC(e)		—			(6	)
Other		(1	)		(3	)

Decrease in interest expense, net	$	(12	)	$	(33	)

(a)	In 2008, ComEd reached a settlement with the IRS resulting in an $8 million decrease in 2008 interest expense. See Note 11 of the Combined Notes to the Consolidated Financial Statements for more information.

(b)	ComEd Financing II and ComEd Transitional Funding Trust were dissolved in 2008.

(c)	During the first quarter of 2008, ComEd recorded an increase in interest expense of $6 million related to a 2007 settlement with the IRS of a research and development claim.

(d)

During 2009, ComEd recorded $66 million of interest benefit associated with the remeasurement of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48) income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets, of which, $6 million was recorded as a reversal of interest expense with the remainder recorded in Other, net.

(e)	In 2008, interest expense included a $7 million charge to reverse previously recognized AFUDC resulting from the January 18, 2008 FERC order granting incentive treatment on ComEd’s largest transmission project

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Other, net

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Other, net increased during the second quarter of 2009 compared to 2008 primarily due to $60 million of interest income associated with the remeasurement of FIN 48 income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets. This increase was partially offset by an other-than-temporary impairment of $7 million recorded to ComEd’s investments held in Rabbi trusts during the second quarter of 2009. See Note 6 and Note 11 of the Combined Notes to the Consolidated Financial Statements for additional information.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Other, net increased for the six months ended June 30, 2009 compared to 2008 due to $29 million of interest income recognized associated with the 2009 Illinois Supreme Court ruling concerning ComEd’s claim for refunds for Illinois investment tax credits. On July 15, 2009, the Illinois Supreme Court changed its opinion related to this decision to indicate the treatment of electricity as tangible personal property will be applied only prospectively. Unless the Supreme Court changes its position again, ComEd will record a charge in the third quarter to reverse income previously recognized. In addition, other, net was higher due to $60 million of 2009 interest income associated with the remeasurement of FIN 48 income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets. These increases were partially offset by an other-than-temporary impairment of $7 million recorded to ComEd’s investments held in Rabbi trusts during the second quarter of 2009. See Note 6 and Note 11 of the Combined Notes to Consolidated Financial Statements for additional information.

Effective income tax rate

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. ComEd’s effective income tax rate for the three months ended June 30, 2009 was 38.6%, as compared to 37.5% for the three months ended June 30, 2008. The increase in the effective tax rate was primarily a result of increased income while permanent differences remained relatively constant.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. ComEd’s effective income tax rate for the six months ended June 30, 2009 was 32.9%, as compared to 38.2% for the six months ended June 30, 2008. ComEd’s effective tax rate decreased as a result of a reduction in state income tax expense primarily driven by an Illinois Supreme Court decision granting ITC to Exelon. On July 15, 2009, the Illinois Supreme Court changed its opinion related to this decision to indicate the treatment of electricity as tangible personal property will be applied only prospectively. Unless the Supreme Court changes its position again, ComEd will record a charge in the third quarter to reverse income previously recognized. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding the components of the effective income tax rates.

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ComEd Electric Operating Statistics and Revenue Detail


	Three Months Ended June 30,		% Change	Six Months Ended June 30,		% Change
Retail Deliveries (in GWhs)	2009	2008	% Change	2009	2008	% Change
Full service(a)
Residential	6,032	6,119	(1.4)%	13,095	13,407	(2.3)%
Small commercial & industrial	3,272	3,543	(7.6)%	6,951	7,345	(5.4)%
Large commercial & industrial	258	174	48.3 %	629	484	30.0 %
Public authorities & electric railroads	101	133	(24.1)%	207	313	(33.9)%

Total full service	9,663	9,969	(3.1)%	20,882	21,549	(3.1)%

Delivery only(b)
Residential(c)	—	—	n.m	—	—	n.m
Small commercial & industrial	4,467	4,522	(1.2)%	8,938	9,097	(1.7)%
Large commercial & industrial	6,210	6,830	(9.1)%	12,613	13,754	(8.3)%
Public authorities & electric railroads	174	119	46.2 %	414	286	44.8 %

Total delivery only	10,851	11,471	(5.4)%	21,965	23,137	(5.1)%

Total retail deliveries	20,514	21,440	(4.3)%	42,847	44,686	(4.1)%

(a)	Reflects deliveries to customers purchasing electricity from ComEd.

(b)	Reflects customers electing to purchase electricity from an alternative electric generation supplier.

(c)	There are a minimal number of residential customers being served by alternative electric generation suppliers with total activity for the three and six months ended June 30, 2009 of less than 1 GWh and $1 million.

n.m. Not meaningful.


	Three Months Ended June 30,				% Change	Six Months Ended June 30,				% Change
Electric Revenue	2009		2008		% Change	2009		2008		% Change
Full service(a)
Residential	$	731	$	732	(0.1)%	$	1,577	$	1,493	5.6 %
Small commercial & industrial		328		379	(13.5)%		705		741	(4.9)%
Large commercial & industrial		14		18	(22.2)%		39		43	(9.3)%
Public authorities & electric railroads		11		10	10 %		22		27	(18.5)%

Total full service		1,084		1,139	(4.8)%		2,343		2,304	1.7 %

Delivery only(b)
Residential(c)		—		—	n.m		—		—	n.m
Small commercial & industrial		83		72	15.3 %		155		136	14.0 %
Large commercial & industrial		79		71	11.3 %		153		136	12.5 %
Public authorities & electric railroads		3		1	n.m		7		3	n.m

Total delivery only		165		144	14.6 %		315		275	14.5 %

Total electric retail revenues		1,249		1,283	(2.7)%		2,658		2,579	3.1 %

Other revenue(d)		140		142	(1.4)%		284		286	(0.7)%

Total electric and other revenue	$	1,389	$	1,425	(2.5)%	$	2,942	$	2,865	2.7 %

(a)	Reflects deliveries to customers purchasing electricity from ComEd, which include the cost of electricity and the cost of transmission and distribution of the electricity.

(b)	Reflects revenue under tariff rates from customers electing to purchase electricity from an alternative electric generation supplier.

(c)	There are a minimal number of residential customers being served by alternative electric generation suppliers with total activity for the three and six months ended June 30, 2009 of less than 1 GWh and $1 million.

(d)	Other revenues primarily include transmission revenue from PJM. Other items include late payment charges and mutual assistance program revenues.

n.m. Not meaningful.

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Results of Operations — PECO


	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2009			2008			Favorable (Unfavorable) Variance			2009			2008			Favorable (Unfavorable) Variance
Operating revenues	$	1,204		$	1,277		$	(73	)	$	2,718		$	2,754		$	(36	)
Purchased power and fuel		602			674			72			1,437			1,513			76

Revenue net of purchased power and fuel		602			603			(1	)		1,281			1,241			40

Other operating expenses
Operating and maintenance		149			196			47			327			365			38
Depreciation and amortization		230			205			(25	)		455			411			(44	)
Taxes other than income		69			64			(5	)		135			129			(6	)

Total other operating expenses		448			465			17			917			905			(12	)

Operating income		154			138			16			364			336			28

Other income and deductions
Interest expense, net		(49	)		(58	)		9			(99	)		(116	)		17
Equity in losses of unconsolidated affiliates		(6	)		(4	)		(2	)		(12	)		(7	)		(5	)
Other, net		3			7			(4	)		6			11			(5	)

Total other income and deductions		(52	)		(55	)		3			(105	)		(112	)		7

Income before income taxes		102			83			19			259			224			35
Income taxes		31			25			(6	)		76			69			(7	)

Net income		71			58			13			183			155			28
Preferred security dividends		1			1			—			2			2			—

Net income on common stock	$	70		$	57		$	13		$	181		$	153		$	28

Net Income.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. PECO’s net income for the three months ended June 30, 2009 compared to the same period in 2008 increased due to lower operating and maintenance expenses, primarily driven by decreased allowance for uncollectible accounts expense. The lower expense was partially offset by increased scheduled CTC amortization in accordance with PECO’s 1998 settlement of its restructuring case mandated by the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act). Operating revenues net of purchased power and fuel expense remained about level, which reflected increased gas distribution rates effective January 1, 2009, partially offset by lower revenues as a result of reduced load, largely reflecting decreased residential and large commercial and industrial electric deliveries primarily driven by the current economic conditions and the impact of unfavorable 2009 weather.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. PECO’s net income for the six months ended June 30, 2009 compared to the same period in 2008 increased due to higher operating revenues net of purchased power and fuel expense, which reflected increased gas distribution rates effective January 1, 2009 and the impact of lower PECO electric distribution rates in 2008 due to the refund of the 2007 PURTA settlement to customers. The increase was partially offset by lower revenues as a result of reduced load, largely reflecting decreased residential and large commercial and industrial electric deliveries primarily driven by economic conditions. Also contributing to the increase in net income were lower operating and maintenance expenses, which reflected decreased allowance for uncollectible accounts expense, partially offset by increased scheduled CTC amortization in accordance with PECO’s 1998 settlement of its restructuring case mandated by the Competition Act.

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Operating Revenues, Purchased Power and Fuel Expense. PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric and revenue net of fuel expense for gas. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its operational performance. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

The changes in PECO’s operating revenues, purchased power and fuel expense and revenue net of purchased power and fuel expense for the three months ended June 30, 2009 compared to the same period in 2008 consisted of the following:


	Increase (Decrease)
	Electric									Gas								Total
	Operating Revenues			Purchased Power			Net			Operating Revenues			Fuel Expense			Net		Operating Revenues			Purchased Power and Fuel Expense			Net
Weather	$	(35	)	$	(16	)	$	(19	)	$	—		$	—		$	—	$	(35	)	$	(16	)	$	(19	)
Gas distribution rate increase		—			—			—			10			—			10		10			—			10
Volume		(40	)		(20	)		(20	)		3			2			1		(37	)		(18	)		(19	)
Pricing		4			(10	)		14			—			—			—		4			(10	)		14
Purchased gas rate decrease		—			—			—			(27	)		(27	)		—		(27	)		(27	)		—
Customer choice		2			2			—			—			—			—		2			2			—
Other		10			(3	)		13			—			—			—		10			(3	)		13

Total increase (decrease)	$	(59	)	$	(47	)	$	(12	)	$	(14	)	$	(25	)	$	11	$	(73	)	$	(72	)	$	(1	)

The changes in PECO’s operating revenues, purchased power and fuel expense and revenue net of purchased power and fuel expense for the six months ended June 30, 2009 compared to the same period in 2008 consisted of the following:


	Increase (Decrease)
	Electric									Gas								Total
	Operating Revenues			Purchased Power			Net			Operating Revenues			Fuel Expense			Net		Operating Revenues			Purchased Power and Fuel Expense			Net
Weather	$	(9	)	$	(4	)	$	(5	)	$	39		$	31		$	8	$	30		$	27		$	3
Gas distribution rate increase		—			—			—			40			—			40		40			—			40
Volume		(61	)		(31	)		(30	)		(7	)		(7	)		—		(68	)		(38	)		(30	)
Pricing		(4	)		(14	)		10			—			—			—		(4	)		(14	)		10
Purchased gas rate decrease		—			—			—			(46	)		(46	)		—		(46	)		(46	)		—
Customer choice		3			3			—			—			—			—		3			3			—
Other		14			(3	)		17			(5	)		(5	)		—		9			(8	)		17

Total increase (decrease)	$	(57	)	$	(49	)	$	(8	)	$	21		$	(27	)	$	48	$	(36	)	$	(76	)	$	40

Weather

Revenues. The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions

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result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2009 compared to the same period in 2008, electric revenues were lower due to the impact of unfavorable 2009 weather conditions in PECO’s service territory. For the three months ended June 30, 2009, cooling degree days were 10% lower than the same period in 2008. During the six months ended June 30, 2009 compared to the same period in 2008, gas revenues were higher due to the impact of unfavorable weather conditions in PECO’s service territory in the winter months of 2008. For the six months ended June 30, 2009, heating degree days were 8% higher and cooling degree days were 10% lower than the same period in 2008. Heating degree days and cooling degrees days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business.

Purchased Power and Fuel Expense. The decrease in purchased power expense attributable to weather for the three months ended June 30, 2009 reflected the impact of unfavorable 2009 weather conditions in the PECO service territory. The increase in fuel expense attributable to weather for the six months ended June 30, 2009 reflected the impact of unfavorable weather conditions in the PECO service territory in the winter months of 2008.

Gas distribution rate increase

Revenues. The increase in gas revenues for the three and six months ended June 30, 2009 compared to the same periods in 2008 reflected increased distribution rates effective January 1, 2009 resulting from the settlement of the 2008 gas distribution rate case.

Volume

Revenues. The decrease in revenues as a result of lower delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2009 as compared to the same periods in 2008, reflected decreased usage per customer, primarily in the residential and large commercial and industrial electric customer classes.

Purchased Power and Fuel Expense. The decrease in purchased power and fuel expense as a result of lower delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2009 as compared to the same periods in 2008, reflected decreased usage per customer, primarily in the residential and large commercial and industrial electric customer classes.

The reduced load, exclusive of the effects of weather, experienced during the three and six months ended June 30, 2009 compared to the same periods in 2008 is expected to continue throughout 2009 due to the current economic conditions.

Pricing

Revenues. The increase in electric revenues as a result of pricing for the three months ended June 30, 2009 compared to the same period in 2008 reflected the impact of lower PECO electric distribution rates in 2008 due to the refund of the 2007 PURTA settlement to customers, as well as other factors that were not individually significant. The rate change had no impact on operating income because it was offset by the amortization of the regulatory liability related to the 2007 PURTA settlement reflected in taxes other than income. The increase was partially offset by a decrease in electric revenues attributable to lower energy market prices charged to certain large commercial and industrial customers (this decrease was completely offset by a related decrease in purchased power expense and had no impact on PECO’s operating income).

The decrease in electric revenues as a result of pricing for the six months ended June 30, 2009 compared to the same period in 2008 reflected lower energy market prices charged to certain large commercial and industrial customers (this decrease was completely offset by a related decrease in purchased power expense and had no

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impact on PECO’s operating income), as well as other factors that were not individually significant. The decrease was partially offset by an increase in electric distribution revenues due to the impact of the reduction in distribution rates in 2008 to refund the 2007 PURTA settlement to customers.

Purchased Power Expense. The decrease in purchased power expense as a result of pricing for the three and six months ended June 30, 2009 as compared to the same periods in 2008 reflected the lower energy market prices, at which rate PECO procures electricity on behalf of certain large commercial and industrial customers.

Purchased gas rate decrease

Revenues. The decrease in gas revenues was due to lower PAPUC-approved rates charged to customers for natural gas. The average purchased gas cost rate per million cubic feet in effect for the three and six months ended June 30, 2009 was 29% and 17% lower, respectively, than the average rate for the same periods in 2008.

Fuel Expense. The decrease in fuel expense for the three and six months ended June 30, 2009 as compared to the same periods in 2008 reflected lower realized natural gas prices.

Customer choice

Revenues and Purchased Power Expense. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. PECO’s operating income is not affected by customer choice because any increase or decrease in revenues is completely offset by a related increase or decrease in purchased power expense.

The increase in electric revenue and purchased power expense associated with customer choice for the three and six months ended June 30, 2009 as compared to the same periods in 2008 reflected increased customers, primarily from the small commercial and industrial customer class, returning to PECO as their electric supplier.

Other

Revenues. The increase in other electric revenues for the three and six months ended June 30, 2009 as compared to the same periods in 2008 reflected an increase in revenues associated with volume fluctuations among customer classes, which resulted in a different profile of rates as different customer classes are charged different rates. The increase was partially offset by decreased spot market activity. Spot market sales revenue results from the sale of scheduled energy transactions that exceed the actual load on the delivery day.

The decrease in other gas revenues for the six months ended June 30, 2009 as compared to the same period in 2008 reflected decreased off-system gas sales activity, as well as other factors that were not individually significant. Off-system gas sales revenues represent sales of excess gas supply on the wholesale market and the release of pipeline capacity.

Purchased Power and Fuel Expense. The decrease in other purchased power expense for the three and six months ended June 30, 2009 as compared to the same periods in 2008 reflected decreased transmission expense and spot market activity. Transmission expenses represent wholesale transmission costs and other costs allocated by PJM, including charges for transmission system stabilization, default charges and regional transmission

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expansion plan costs. Spot market purchases result from scheduled energy transactions that are insufficient to cover the actual load on the delivery day. Also, spot market purchased power expense reflects the net spot market sales and purchases activity that is passed through to Generation in accordance with the PPA. Therefore, spot market activity has no impact on PECO’s operating income.

The decrease in other fuel expense for the six months ended June 30, 2009 as compared to the same period in 2008 reflected decreased off-system gas sales activity, as well as other factors that were not individually significant. Fuel expense related to off-system gas sales includes the cost of gas sold in the wholesale market.

Operating and Maintenance Expense. The decrease in operating and maintenance expense for the three and six months ended June 30, 2009 compared to the same period in 2008, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,
	Increase (Decrease)			Increase (Decrease)
Allowance for uncollectible accounts expense.	$	(50	)	$	(42	)
Storm related costs		(4	)		(6	)
Insurance claims		(2	)		(2	)
Severance		5			5
Fringe benefits		2			4
Wages and salaries		2			3

Decrease in operating and maintenance expense	$	(47	)	$	(38	)

Allowance for uncollectible accounts expense. The decrease in allowance for uncollectible accounts expense at PECO is primarily due to the impact of improved accounts receivable aging resulting from increased collection activities initiated in 2008.

Depreciation and Amortization Expense.

The increase in depreciation and amortization expense for the three and six months ended June 30, 2009 compared to the same periods in 2008 was primarily due to an increase in CTC amortization of $23 million and $41 million, respectively. PECO’s additional amortization of the CTC was in accordance with its original settlement under the Competition Act.

Taxes Other Than Income.

The increase in taxes other than income for the three and six months ended June 30, 2009 compared to the same periods in 2008 was primarily due to a decrease in the regulatory liability amortization related to the 2007 PURTA settlement that became fully amortized in January 2009. The impact of the amortization on operating income was offset by lower revenues due to a reduction in the electric distribution rates to refund the 2007 PURTA settlement to customers. The increase was partially offset by a decrease in gross receipts tax expense due to a rate reduction.

Interest Expense, Net.

The decrease in interest expense, net for the three and six months ended June 30, 2009 compared to the same periods in 2008 was primarily due to a decrease in the outstanding debt balance due to PETT as a result of scheduled principal payments, partially offset by a higher principal amount of long-term first and refunding mortgage bonds outstanding.

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Other, Net.

The decrease in other, net for the three and six months ended June 30, 2009 compared to the same periods in 2008 was primarily due to the impact of the increase in interest income associated with the simplified service cost method (SSCM) settlement in May 2008. See Note 15 of the Combined Notes to the Consolidated Financial Statements for further details of the components of other, net.

Effective Income Tax Rate.

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. PECO’s effective income tax rate remained relatively constant for the three months ended June 30, 2009 at 30.4% as compared to 30.1% for the three months ended June 30, 2008. See Note 11 of the Combined Notes to the Consolidated Financial Statements for further details.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. PECO’s effective income tax rate for the six months ended June 30, 2009 was 29.3% as compared to 30.8% for the six months ended June 30, 2008. The decrease in the effective tax rate was primarily due to a decrease in state income tax expense due to higher deductible interest expense partially offset by the impact of a tax benefit recorded in the 2008 settlement of Internal Revenue Service matters. See Note 11 of the Combined Notes to the Consolidated Financial Statements for further details.

PECO Electric Operating Statistics and Revenue Detail

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


	Three Months Ended June 30,		% Change		Six Months Ended June 30,		% Change
Retail deliveries to customers (in GWhs)	2009	2008	% Change		2009	2008	% Change
Full service(a)
Residential	2,759	2,941	(6.2	)%	6,287	6,348	(1.0	)%
Small commercial & industrial	1,929	1,960	(1.6	)%	4,027	4,000	0.7	%
Large commercial & industrial	3,877	4,142	(6.4	)%	7,667	8,075	(5.1	)%
Public authorities & electric railroads	222	226	(1.8	)%	469	460	2.0	%

Total full service	8,787	9,269	(5.2	)%	18,450	18,883	(2.3	)%

Delivery only(b)
Residential	5	7	(28.6	)%	12	15	(20.0	)%
Small commercial & industrial	84	115	(27.0	)%	182	239	(23.8	)%
Large commercial & industrial	1	—	100.0	%	2	2	0.0	%

Total delivery only	90	122	(26.2	)%	196	256	(23.4	)%

Total retail deliveries	8,877	9,391	(5.5	)%	18,646	19,139	(2.6	)%

(a)	Full service reflects deliveries to customers purchasing electricity directly from PECO.

(b)	Delivery only service reflects deliveries to customers electing to receive electric generation service from a competitive electric generation supplier.

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	Three Months Ended June 30,				% Change		Six Months Ended June 30,				% Change
Electric revenue	2009		2008		% Change		2009		2008		% Change
Full service(a)
Residential	$	415	$	442	(6.1	)%	$	881	$	894	(1.5	)%
Small commercial & industrial		256		261	(1.9	)%		501		501	0.0	%
Large commercial & industrial		338		359	(5.8	)%		657		698	(5.9	)%
Public authorities & electric railroads		22		22	0.0	%		45		44	2.3	%

Total full service		1,031		1,084	(4.9	)%		2,084		2,137	(2.5	)%

Delivery only(b)
Residential		1		1	0.0	%		1		1	0.0	%
Small commercial & industrial		4		6	(33.3	)%		9		13	(30.8	)%
Large commercial & industrial		—		—	0.0	%		—		—	0.0	%

Total delivery only		5		7	(28.6	)%		10		14	(28.6	)%

Total electric retail revenues		1,036		1,091	(5.0	)%		2,094		2,151	(2.6	)%

Other revenue(c)		67		71	(5.6	)%		135		135	0.0	%

Total electric and other revenue	$	1,103	$	1,162	(5.1	)%	$	2,229	$	2,286	(2.5	)%

(a)	Full service revenue reflects revenue from customers purchasing electricity directly from PECO, 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 electing to receive electric generation service from a competitive electric generation supplier, which includes a distribution charge and a CTC.

(c)	Other revenue includes 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:


Deliveries to customers (in million cubic feet (mmcf))	Three Months Ended June 30,		% Change		Six Months Ended June 30,		% Change
Deliveries to customers (in million cubic feet (mmcf))	2009	2008	% Change		2009	2008	% Change
Retail sales	7,136	6,838	4.4	%	35,750	33,185	7.7	%
Transportation	6,105	6,158	(0.9	)%	13,983	14,351	(2.6	)%

Total gas deliveries	13,241	12,996	1.9	%	49,733	47,536	4.6	%


	Three Months Ended June 30,				% Change		Six Months Ended June 30,				% Change
Gas revenue	2009		2008		% Change		2009		2008		% Change
Retail sales	$	95	$	109	(12.8	)%	$	475	$	452	5.1	%
Transportation		4		4	0.0	%		10		10	0.0	%
Resales and other		2		2	0.0	%		4		6	(33.3	)%

Total gas revenue	$	101	$	115	(12.2	)%	$	489	$	468	4.5	%

Liquidity and Capital Resources

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market

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business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, ComEd and PECO have access to unsecured revolving credit facilities with aggregate bank commitments of $957 million, $4.8 billion, $952 million and $574 million, respectively. The Registrants’ credit facilities extend through October 2012 for Exelon, Generation and PECO and February 2011 for ComEd. Exelon, Generation, and PECO utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. ComEd uses its credit facilities to provide for short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. Future acquisitions that Exelon may undertake may involve external debt financing or the issuance of additional Exelon common stock. See PART I. ITEM 1A. Risk Factors of Exelon’s 2008 Annual Report on Form 10-K for risks related to the proposed acquisition of NRG. See Note 7 of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

General

Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers. ComEd’s and PECO’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, gas distribution services to an established and diverse base of retail customers. ComEd’s and PECO’s future cash flows may be affected by the economy, weather, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. See Notes 3 and 14 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

Pension and Other Postretirement Benefits

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and Exelon’s estimated obligations under the plans. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual and assumed rates of return on plan assets. During 2008, the unfunded status of Exelon’s plans increased significantly, to $6.38 billion at December 31, 2008, primarily due to lower than expected asset returns. Exelon has continued to monitor financial market conditions and their impact on the plans during the first half of 2009.

On December 23, 2008, President Bush signed the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which allows the use of average assets, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements, among other provisions. Exelon has not yet determined whether it will elect this option, referred to as asset smoothing. Election of asset smoothing would provide Exelon the opportunity to defer certain contributions to later years or potentially mitigate future contributions through market recovery.

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On March 31, 2009, the U.S. Treasury Department provided guidance on the selection of the corporate bond yield curve for determining plan liabilities and allows companies to choose from a range of months in selecting a rate, rather than requiring the use of the rate in the month of measurement (December for calendar year-end companies). The U.S. Treasury Department’s announcement specifically referenced 2009, but also indicated that technical guidance will be forthcoming to address future years. Application of this guidance, which is elective, would have the effect of reducing Exelon’s 2009 pension funding requirements and deferring certain contributions to later years. There are other legislative and regulatory funding relief proposals also being discussed. Exelon is monitoring the progress of these initiatives and evaluating their potential impact on funding requirements and strategies.

For financial reporting purposes, the unfunded status of the plans is updated annually, at December 31. Projecting the unfunded status of the plans at any interim period requires development of numerous assumptions, the most significant of which are the discount rate and the current year’s asset performance. Exelon’s pension and postretirement benefit plans experienced combined actual asset returns of approximately 5% and negative 26% for the six months ended June 30, 2009 and year ended December 31, 2008, respectively.

In order to provide additional information about the potential impact of current financial market conditions on the plans, Exelon has estimated the unfunded status of the pension and postretirement welfare plans at June 30, 2009 to be $4,019 million and $2,113 million, respectively, representing a decrease of $105 million and of $143 million, respectively, from December 31, 2008. These unfunded status estimates assume asset returns of approximately 5.0% and 5.9% for pension and postretirement assets, respectively, and an increase of approximately 15 basis points in the assumed discount rate since year-end. Management considers various factors when making funding decisions, including actuarially determined minimum contribution requirements under the Employee Retirement Income Security Act, as amended, and contributions required to avoid benefit restrictions for the pension plans. Regulatory requirements and the amount deductible for income tax purposes are among the factors considered in determining funding for the other postretirement benefit plans.

Management has estimated future pension contributions utilizing the guidance announced by the U.S. Treasury Department and assuming an estimated unfunded status for the pension plans of $4,019 million at June 30, 2009. The estimated pension contributions summarized below include required contributions and contributions necessary to avoid benefit restrictions:


	2010		2011		2012		2013		2014		Cumulative
Expected contributions	$	169	$	1,139	$	1,131	$	1,152	$	941	$	4,532

Tax Matters

During 2008, Generation benefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified nuclear decommissioning trust fund to a qualified nuclear decommissioning trust fund. As a result of interpretative guidance published by the Internal Revenue Service with respect to this provision in the Energy Policy Act of 2005, Generation completed a special transfer in the first quarter of 2008, which resulted in net positive cash flow of approximately $280 million in total for 2008 and 2009 combined.

In addition, Exelon, through ComEd, has taken certain tax positions to defer the tax gain on the 1999 sale of its fossil generating assets. The IRS has disallowed the deferral of the gain on this sale. As more fully described in Note 11 of the Combined Notes to Consolidated Financial Statements, a fully successful IRS challenge to Exelon’s and ComEd’s positions would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable

The American Recovery and Reinvestment Act of 2009 (ARRA of 2009) was enacted February 17, 2009 and includes an incentive that allows companies to claim an accelerated depreciation deduction for Federal

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income tax purposes equal to 50% of the cost basis of certain property placed in service during 2009. Exelon continues to evaluate the impact the ARRA of 2009 will have on our cash flows in 2009, and currently estimates the impact to be a reduction of its 2009 Federal income tax liability of at least $300 million.

Given the current economic environment, state and local governments are facing increasing financial challenges, which may increase the risk of additional income tax levies, property taxes, and other taxes.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the six months ended June 30, 2009 and 2008:


	Six Months Ended June 30,						Variance
	2009			2008			Variance
Net income	$	1,369		$	1,329		$	40
Add (subtract):
Non-cash operating activities(a)		2,021			1,429			592
Pension and non-pension postretirement benefit contributions		(68	)		(56	)		(12	)
Income Taxes		(177	)		277			(454	)
Changes in working capital and other noncurrent assets and liabilities(b)		(344	)		(542	)		198
Counterparty collateral (net)		246			(763	)		1,009

Net cash flows provided by operations	$	3,047		$	1,674		$	1,373

(a)

Represents depreciation, amortization and accretion, net mark-to-market gains on derivative transactions, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related activities, stock compensation expense, impairment of long-lived assets, and other non-cash charges.

(b)	Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper and the current portion of long-term debt.

Cash flows provided by operations for the six months ended June 30, 2009 and 2008 by Registrant were as follows:


	Six Months Ended March 31,
	2009		2008
Exelon	$	3,047	$	1,674
Generation		2,014		756
ComEd		581		623
PECO		584		553

Changes in Exelon’s, Generation’s, ComEd’s and PECO’s cash flows from operations were generally consistent with changes in each Registrant’s respective 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, 2009 and 2008 were as follows:

Generation

•

During the six months ended June 30, 2009 and 2008, Generation had net collections of counterparty collateral of $245 million and net disbursements of counterparty collateral of $832 million, respectively. The change in collections and disbursements was primarily due to changes in market conditions that resulted in an increased mark-to-market asset position. When Generation is in a mark-to-market liability position and is required to post collateral with its counterparties, the collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.

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•

During 2007, Generation, along with ComEd and other generators and utilities, reached an agreement with various representatives from the State of Illinois to address concerns about higher electric bills in Illinois. Generation committed to contributing approximately $747 million over four years. As part of the agreement, during the six months ended June 30, 2009 and 2008, Generation contributed cash of approximately $67 million and $171 million, respectively.

•

During the six months ended June 30, 2009 and June 30, 2008, Generation’s accounts receivable from ComEd for energy purchases related to its supplier forward contract, ICC approved RFP contracts and financial swap contract increased (decreased) by ($68) million and $79 million, respectively.

•

During the six months ended June 30, 2009 and June 30, 2008, Generation’s accounts receivable from PECO under the PPA increased by $55 million and $55 million, respectively.

ComEd

•

During the six months ended June 30, 2009 and June 30, 2008, ComEd’s payables to Generation for energy purchases related to its supplier forward contract, ICC approved RFP contracts and financial swap contract increased (decreased) by $(68) million and $79 million, respectively. During the six months ended June 30, 2009 and June 30, 2008, ComEd’s payables to other energy suppliers for energy purchases increased (decreased) by $(39) million and $85 million, respectively.

PECO

•

During the six months ended June 30, 2009 and June 30, 2008, PECO’s prepaid utility taxes increased by $129 million and $69 million, respectively, primarily due to the Pennsylvania Gross Receipts Tax prepayment in March of each year.

•

During the six months ended June 30, 2009 and June 30, 2008, PECO’s payables to Generation under the PPA increased by $55 million and $55 million, respectively. During the six months ended June 30, 2009 and June 30, 2008, PECO’s payables to other energy suppliers for energy purchases decreased by $42 million and $15 million, respectively. The decrease in payables to other energy suppliers is primarily due to an agreement executed in February 2009 between PECO, Generation and PJM that changed the way that PECO and Generation administer their PPA for default service.

Cash Flows from Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2009 and 2008 by Registrant were as follows:


	Six Months Ended June 30,
	2009			2008
Exelon	$	(1,546	)	$	(1,699	)
Generation		(926	)		(927	)
ComEd		(421	)		(545	)
PECO		(250	)		(198	)

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Capital expenditures by Registrant and business segment for the six months ended June 30, 2009 and projected amounts for the twelve months ended December 31, 2009 are as follows:


	Six Months Ended June 30, 2009		Projected 2009
Generation	$	801	$	2,051
ComEd		423		877
PECO		179		416
Other		41		71

Total Exelon capital expenditures	$	1,444	$	3,415

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation. Approximately 45% of the projected 2009 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Included in the projected 2009 capital expenditures are a series of planned power uprates across the company’s nuclear fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.

As discussed under “EXELON CORPORATION — Executive Overview,” Generation has begun the application process that would allow for the possible construction of a new nuclear plant in Texas, and Generation is considering the development of a 600-megawatt combined-cycle natural gas plant in Pennsylvania. While Generation has not made a decision to build these plants, should Generation decide to build these or other plants in the future, substantial additional resources would be required. Such capital projects would have a material impact on the use of Exelon’s and Generation’s capital resources.

ComEd and PECO. Approximately 62% and 51% of the projected 2009 capital expenditures at ComEd and PECO, respectively, are for continuing projects to maintain and improve the reliability of their transmission and distribution systems. The remaining amounts are for capital additions to support new business and customer growth. ComEd and PECO are each continuing to evaluate their total capital spending requirements. In 2009, ComEd reduced projected capital expenditures from its previous estimate of $1 billion based on current and projected declining load due to the overall negative economic conditions. ComEd anticipates that it will fund its capital expenditures by internally generated funds. PECO anticipates that it will fund its capital expenditures by internally generated funds and borrowings.

Other significant investing activities of the Registrants for the six months ended June 30, 2009 and 2008 were as follows:

PECO. As of June 30, 2009, PECO contributed $74 million to the Exelon intercompany money pool. As of June 30^,2008, PECO had no contributions to the Exelon intercompany money pool.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the six months ended June 30, 2009 and 2008 by Registrant were as follows:


	Six Months Ended June 30,
	2009			2008
Exelon	$	(934	)	$	46
Generation		(674	)		95
ComEd		(152	)		62
PECO		(173	)		(358	)

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Debt. Debt activity for the six months ended June 30, 2009 and 2008 was as follows:


Company	Issuance of long-term debt during the six months ended June 30, 2009	Use of proceeds
Generation	$46 million of 3-year term rate Pollution Control Notes at 5.00% with a final maturity of December 1, 2042	Used to refinance $46 million of unenhanced tax-exempt variable rate debt that was repurchased in February 23, 2009(b).

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 (a)	Used to repay credit facility borrowings incurred to repurchase bonds (c)

ComEd	$91 million tax-exempt variable rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 (a)	Used to repay credit facility borrowings incurred to repurchase bonds (c)

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 (a)	Used to repay credit facility borrowings incurred to repurchase bonds (b)

PECO	$250 million of First and Refunding Mortgage Bonds, 5.00% due October 1, 2014	Used to refinance short-term debt and for other general corporate purposes.

(a)	Remarketed in May 2009 with letter of credit issued under credit facility.

(b)	Repurchase due to failed remarketing.

(c)	Repurchase required due to expiration of existing letter of credit.


Company	Issuance of long-term debt during the six months ended June 30, 2008	Use of proceeds
ComEd	$450 million of First Mortgage 6.45% Bonds, Series 107, due January 15, 2038	Used to retire $295 million of First Mortgage Bonds, Series 99, to call and refinance $155 million of trust preferred securities and for other general corporate purposes.

ComEd	$700 million of First Mortgage 5.80% Bonds, Series 108, due March 15, 2018	Used to repay a portion of borrowings under ComEd’s revolving credit facility, to provide for the retirement at scheduled maturity in May 2008 of $120 million of First Mortgage bonds, Series 83, and for general corporate purposes.

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 (a)(b)	Used to refinance $50 million tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2003 C, due March 1, 2020

ComEd	$91 million tax-exempt variable rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 (a)(b)	Used to refinance $91 million tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2005, due March 1, 2017

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 (a)(b)	Used to refinance a portion of the outstanding tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2003, 2003 B and 2003 D, due May 15, 2017, November 1, 2019 and January 15, 2014

PECO	$150 million of First and Refunding Mortgage Bonds, 4.00% due December 1, 2012(c)	Used to retire First and Refunding Mortgage Bonds, variable rate due December 1, 2012

PECO	$500 million of First and Refunding Mortgage Bonds, 5.35% due March 1, 2018	Used to repay commercial paper and for other general corporate purposes.

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(a)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable weekly-rate tax-exempt pollution control bonds that were issued to refinance variable auction-rate tax-exempt pollution control bonds.

(b)

During the second quarter of 2008, ComEd established a $216 million letter of credit facility, of which $194 million was used to provide credit enhancement to variable-rate tax exempt bonds including $3 million of accrued interest. The new facility expired on May 9, 2009 and the letters of credit are no longer outstanding.

(c)	First and Refunding Mortgage Bonds issued under the PECO mortgage indenture to secure tax-exempt pollution control bonds and notes that were issued to refinance auction-rate tax-exempt pollution control bonds.


Company		Retirement of long-term debt during the six months ended June 30, 2009
Generation		$46 million of Pollution Control Notes with variable interest rates, due December 1, 2042 (a)

Generation		$1 million scheduled payments of 7.83% Kennett Square capital lease until September 20, 2020

ComEd		$91 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 (b)

ComEd		$50 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 (b)

ComEd		$50 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 (c)

ComEd		$16 million of 5.70% First Mortgage Bonds, Series 1994 B, due January 15, 2009

ComEd		$1 million of 4.625-4.75% sinking fund debentures, due at various dates

PECO		$319 million of 7.65% PETT Transition Bonds, due September 1, 2009

PECO		$11 million of 6.52% PETT Transition Bonds, due March 1, 2010

(a)	Repurchased due to a failed remarketing and remarketed in February 2009.

(b)	Repurchased due to expiration of existing letter of credit and remarketed in May 2009.

(c)	Repurchased due to a failed remarketing and remarketed in May 2009.


Company		Retirement of long-term debt during the six months ended June 30, 2008
Exelon		$21 million of 6.00-8.00% notes payable for investments in synthetic fuel-producing facilities, due at various dates

ComEd		$155 million of 8.50% Subordinated Debentures of ComEd Financing II, due January 15, 2027

ComEd		$295 million of 3.70% First Mortgage Bonds, Series 99 due February 1, 2008

ComEd		$120 million of 8.00% First Mortgage Bonds, Series 83 due May 15, 2008

ComEd		$180 million of 5.74% ComEd Transitional Funding Trust, due December 25, 2008

ComEd		$1 million of 3.875% sinking fund debentures, due January 1, 2008

ComEd		$50 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2003 C, due March 1, 2020 (a)

ComEd		$91 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2005, due March 1, 2017 (a)

ComEd		$1 million of 4.75% Sinking fund debentures due December 1, 2011.

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 (b)

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 (b)

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 (b)

PECO		$4 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 (b)

PECO		$450 million of 3.5% First and Refunding Mortgage Bonds, due May 1, 2008

PECO		$207 million of 6.13% PETT Transition Bonds, due September 1, 2008

PECO		$54 million of 7.625% PETT Transition Bonds, due March 1, 2009

Generation		$2 million scheduled payments of 7.83% Kennett Square Capital Lease until September 20, 2020

(a)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable weekly-rate tax-exempt pollution control bonds.

(b)	First and Refunding Mortgage Bonds issued under the PECO mortgage indenture to secure tax-exempt pollution control bonds and notes that were issued to refinance auction rate tax-exempt pollution control bonds.

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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, 2009 and 2008 by Registrant were as follows:


	Six Months Ended June 30,
	2009		2008
Exelon	$	692	$	659
Generation		675		991
ComEd		120		—
PECO		156		238

Short-Term Borrowings. During the six months ended June 30, 2009, Exelon and PECO repaid $151 million and $95 million of commercial paper, respectively. During the six months ended June 30, 2009, ComEd repaid $15 million of outstanding borrowings under its credit agreement. During the six months ended June 30, 2008, Exelon, Generation and PECO issued (repaid) $1,227 million, $1,087 million and $(41) million of commercial paper, respectively. During the six months ended June 30, 2008, ComEd repaid $370 million of outstanding borrowings under its credit agreement.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during the six months ended June 30, 2009 and 2008 by Registrant was as follows:


	Six Months Ended June 30,
	2009		2008
Exelon	$	330	$	596
ComEd		—		335
PECO		330		261

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during the six months ended June 30, 2009 and 2008 by Registrant was as follows:

(a)	Reflect payments received to reduce the parent receivable.

Other. Other significant financing activities for Exelon for the six months ended June 30, 2009 and 2008 were as follows:

•

Exelon received proceeds from employee stock plans of $19 million and $105 million during the six months ended June 30, 2009 and 2008, respectively.

•

Exelon’s other financing activities during the six months ended June 30, 2009 and 2008 include $2 million and $51 million, respectively, of excess tax benefits, which represent the tax deduction in excess of the tax benefit related to compensation cost recognized for stock options exercised.

Credit Matters

Recent Market Conditions

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper

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markets and large, diversified credit facilities ($7.3 billion in aggregate total commitments and $6.8 billion available as of June 30, 2009, of which no financial institution has more than 10% of the aggregate commitments for Exelon, Generation and PECO and 12% for ComEd). Generation also has additional letter of credit facilities used solely to enhance tax-exempt variable rate debt. Certain of these letters of credit with a principal amount of $307 million at Generation, will expire in the third quarter of 2009. Generation plans to remarket certain of these bonds as unenhanced with different interest rate terms and refinance the others with new unenhanced tax-exempt bonds. Exelon, Generation and PECO had access to the commercial paper market during the second quarter and they were able to fund their short-term liquidity needs with commercial paper at favorable rates compared to 2008, when necessary. ComEd utilizes its credit facility to fund its short-term liquidity needs and provide credit enhancement for $191 million of variable rate tax-exempt bonds. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. As the national and world-wide financial markets have continued to be challenging in recent months, the Registrants have continued to closely monitor events and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A Risk Factors of Exelon’s 2008 Annual Report on Form 10-K for further information regarding the effects of a longer-term uncertainty in the capital and credit markets or significant bank failures.

The Registrants believe their cash flow from operations, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2009, it would have been required to provide incremental collateral of approximately $764 million, which is well within its current available credit facility capacities of approximately $4.7 billion. The $764 million includes $557 million of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payable and receivables, net of the contractual right of offset under master netting agreements and $207 million of financial assurances that Generation would be required to provide Nuclear Electric Insurance Limited (NEIL) related to annual retrospective premium obligations. If ComEd lost its investment grade credit rating as of June 30, 2009, it would have been required to provide incremental collateral of approximately $220 million, which is well within its current available credit facility capacity of approximately $570 million. On February 26, 2009, PECO, Generation, and PJM entered into an agreement, based on changes to the way PECO and Generation administer their PPA for default service that enabled PECO’s collateral requirement to PJM to be reduced from $90 million to $5 million. On May 13, 2009, a remeasurement of the collateral requirement under the PJM policy indicated no collateral was required and the $5 million letter of credit was cancelled. If PECO lost its investment grade credit rating as of June 30, 2009, it would have been required to provide collateral of $4 million pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $48 million related to its natural gas procurement contracts, which is well within PECO’s current available credit facility capacity of $564 million.

Exelon Credit Facilities

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool, and ComEd meets its short-term liquidity requirements primarily through borrowings under its credit facility. While short-term borrowing costs have not been significant to date, further uncertainty in the credit markets may result in increased costs for commercial paper borrowings. Continued uncertainty in the credit markets could limit the ability of the Registrants to issue commercial paper, which may increase their reliance on their respective revolving credit facilities for short-term liquidity purposes. The Registrants may use their respective 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 the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

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The following table reflects the Registrants’ commercial paper programs and revolving credit agreements at June 30, 2009.


Commercial Paper Programs
Commercial Paper Issuer	Maximum Program Size(a)		Outstanding Commercial Paper at June 30, 2009		Average Interest Rate on Commercial Paper Borrowings for the six months ended June 30, 2009
Exelon Corporate	$	957	$	—	0.72	%
Generation		4,834		—	—
ComEd(b)		952		—	—
PECO		574		—	0.67	%

(a)	Equals aggregate bank commitments under revolving credit agreements.

(b)	During the six months ended June 30, 2009, ComEd was unable to access the commercial paper market given the market conditions.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.


Revolving Credit Agreements
Borrower	Aggregate Bank Commitment		Outstanding Borrowings/ Facility Draws		Outstanding Letters of Credit		Available Capacity under Revolving Credit Agreements as of June 30, 2009		Average Interest Rate on Borrowings for six months ended June 30, 2009
Exelon Corporate	$	957	$	—	$	5	$	952	—
Generation		4,834		—		156		4,678	—
ComEd		952		45		337		570	0.82	%
PECO		574		—		10		564	—

Interest rates on advances under the credit facilities are based on either prime or the LIBOR plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. In the cases of Exelon, Generation and PECO, the maximum LIBOR adder is 65 basis points; and in the case of ComEd, it is 162.5 basis points.

Each credit agreement requires the affected borrower 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 interest coverage ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and interest on nonrecourse debt. The following table summarizes the minimum thresholds reflected in the credit agreements for the six months ended June 30, 2009:


	Exelon	Generation	ComEd	PECO
Credit agreement threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1

At June 30, 2009, the interest coverage ratios at the Registrants were as follows:


	Exelon	Generation	ComEd	PECO
Interest coverage ratio	13.21	36.49	5.55	5.79

An event of default under any Registrant’s credit facility will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or interest on any indebtedness having a principal amount in excess of $100 million in the aggregate by Generation (including Generation’s credit facility) will constitute an event of default under the Exelon credit facility.

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Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets may depend on the securities ratings of the entity that is accessing the capital markets.

Listed below are the Registrants’ securities ratings as of June 30, 2009.


	Securities	Moody’s Investor Service (Moody’s)	Standard and Poor’s Ratings Group (S&P)	Fitch
Exelon
	Senior unsecured debt	Baa1	BBB-	BBB+
	Commercial paper	P2	A2	F2
Generation
	Senior unsecured debt	A3	BBB	BBB+
	Commercial paper	P2	A2	F2
ComEd
	Senior unsecured debt	Baa3	BBB-	BBB-
	Senior secured debt	Baa2	BBB+	BBB
	Commercial paper	P3	A3	B
PECO
	Senior unsecured debt	A3	BBB	A-
	Senior secured debt	A2	A-	A
	Commercial paper	P1	A2	F2
	Transition bonds(a)	Aaa	AAA	AAA

(a)	Issued by PETT, an unconsolidated affiliate of PECO.

None of the Registrants’ borrowings are subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under the Registrants’ credit agreements.

A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

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downgrade as a basis for making a demand for adequate assurance of future performance. Depending on its net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation’s situation at the time of the demand. If Exelon can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

The terms of the financial swap contract between Generation and ComEd provide that: (1) if ComEd is downgraded below investment grade by Moody’s or S&P, or (2) if Generation is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by the applicable party depending on how market prices compare to the contracted price levels. However, under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation.

PECO’s supplier master agreements that govern the terms of its default service program contracts do not contain provisions that would require PECO to post collateral. PECO’s natural gas procurement contracts contain provisions that require PECO to post collateral. This collateral may be posted in the form of cash or credit support with threshold’s contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty.

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 months ended June 30, 2009 are presented in the following table in addition to the net contribution or borrowing as of June 30, 2009:


	Maximum Contributed		Maximum Borrowed		June 30, 2009 Contributed (Borrowed)
Generation	$	138	$	—	$	—
PECO		106		—		74
BSC		—		140		(87	)
Exelon Corporate		47		N/A		13

Variable-Rate Debt

Generation repurchased $46 million in unenhanced tax-exempt variable rate debt on February 23, 2009 due to a failed remarketing. In June 2009, Generation refinanced the debt with $46 million in bonds at a term rate through May 2012 and a maturity of 2042.

During the second quarter of 2009, ComEd repurchased $191 million of its credit enhanced variable-rate tax-exempt debt. This debt, with maturities ranging from 2017 – 2021, was subsequently remarketed with credit enhancement provided by letters of credit issued under ComEd’s revolving credit facility. The letters of credit expire shortly before the expiration of the credit facility in 2011.

Generation has letter of credit facilities that will expire in the third quarter of 2009, which are used to credit enhance variable rate long-term tax-exempt debt totaling $307 million, with maturities ranging from 2021—2034. Generation plans to remarket certain of these bonds as unenhanced with different interest rate terms and refinance the others with new unenhanced tax-exempt bonds. Generation also has letter of credit facilities that will expire in the second quarter of 2010, which are used to credit enhance tax-exempt variable rate long-term debt totaling $213 million, with maturities ranging from 2016—2034.

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credit. If Generation or ComEd were required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds with an interest rate term not requiring letter of credit support. Generation and ComEd have classified amounts outstanding under these debt agreements as long-term, based on management’s intent and ability to either renew or replace the letters of credit, or refinance the debt at reasonable terms on a long-term fixed-rate basis.

Investments in Nuclear Decommissioning Trust Funds

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the values 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 allocations in accordance with Generation’s nuclear decommissioning trust fund investment policy. With regards to equity securities, Generation’s investment policy establishes limits on the concentration of equity holdings in any one company and also in any one industry. With regards to its fixed-income securities, Generation’s investment policy limits the concentrations of the types of bonds that may be purchased for the trust funds and also requires a minimum percentage of the portfolio to have investment grade ratings (minimum credit quality ratings of “Baa3” by Moody’s, “BBB-” by S&P and “BBB-” by Fitch Ratings) while requiring that the overall portfolio maintain a minimum credit quality rating of “A2”. See “Executive Overview” for further information regarding the trust funds and the NRC’s minimum funding requirements and related liquidity ramifications.

Shelf Registrations

The Registrants filed shelf registration statements that became effective upon filing and are not required to specify the amount of securities to be offered thereon. As of June 30, 2009, the Registrants had current shelf registration statements for the sale of unspecified amounts of securities that were effective with the SEC. The ability of the Registrants to sell securities in the public market or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and current overall capital market business conditions, including that of the utility industry in general.

Regulatory Authorizations

As of June 30, 2009, ComEd had $389 million in long-term debt refinancing authority and, $399 million in new money long-term debt financing authority from the ICC, and $2.5 billion in short-term financing authority from FERC. As of June 30, 2009, PECO had $1.9 billion in long-term debt financing authority from the PAPUC and $1.5 billion in short-term financing authority from FERC.

Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. The Registrants’ contractual obligations and commercial commitments as of June 30, 2009 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2008 Annual Report on Form 10-K except for the following:

Exelon

•

Letters of credit decreased $55 million and guarantees decreased by $201 million primarily as a result of energy trading activities and the reorganization of AmerGen, which was merged into Generation effective January 8, 2009. Guarantees decreased by $270 million for 2009, increased by $106 million for 2010 through 2011, increased by $7 million for 2012 through 2013 and decreased by $44 million for 2014 and beyond.

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•

Exelon’s other purchase obligations, which primarily represent commitments for services, materials and information increased $178 million for 2009, $67 million for 2010 through 2011 and $9 million for 2012 through 2013, and decreased $3 million for 2014 and beyond.

•

See “Cash Flows From Operating Activities — Pension and Other Postretirement Benefits” above for estimated future pension contributions utilizing the newly issued guidance from the U.S. Treasury Department and assuming an estimated unfunded status for the pension plans of $4,019 million at June 30, 2009. The estimated qualified pension contributions include required contributions and contributions necessary to avoid benefit restrictions.

Generation

•

Letters of credit increased by $28 million and guarantees decreased by $192 million primarily as a result of energy trading activities and the reorganization of AmerGen, which was merged into Generation effective January 8, 2009. Guarantees decreased by $293 million for 2009 and increased by $101 million for 2010 and 2011 as a result of energy trading activities.

•

Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $535 million during the six months ended June 30, 2009, reflecting increases of approximately $503 million, $594 million, $277 million, $26 million and $5 million related to 2010, 2011, 2012, 2013 and 2014 and beyond sales commitments, respectively, offset by the fulfillment of approximately $870 million of 2009 commitments during the six months ended June 30, 2009. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s hedging program.

•

Generation’s other purchase obligations, which primarily represent commitments for services, materials and information increased $40 million for 2009, $41 million for 2010 through 2011 and $5 million for 2012 through 2013, and decreased $3 million for 2014 and beyond.

ComEd

•

In May 2009, ComEd entered into contracts for the procurement of renewable energy credits totaling approximately $31 million. Through June 30, 2009, $12 million had been purchased, with $19 million to be purchased by May 31, 2010. See Note 3 of the Combined Notes to Consolidated Financial Statements for further information.

•

ComEd’s PJM regional transmission expansion plan (RTEP) baseline project commitments decreased by $28 million, $32 million and $5 million for 2009, 2010 and 2013, respectively and increased by $23 million for 2010 and 2013 driven by changes in estimated timing and amount of project spending.

•

ComEd’s other purchase obligations, which primarily represent commitments for services, materials and information increased $13 million for 2009 and $4 million for 2010 through 2011.

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PECO

•

PECO issued $250 million First and Refunding Mortgage Bonds, 5.0% due October 1, 2014. The net proceeds from the sale of the bonds were used to refinance commercial paper and for other general corporate purposes.

•

PECO’s PJM RTEP baseline project commitments increased by $3 million in both 2011 and 2012 due to the addition of newly designated RTEP projects.

•

PECO’s total natural gas purchase obligations increased by approximately $50 million during the six months ended June 30, 2009, reflecting an increase of $20 million, $24 million and $6 million in 2009, 2010 and 2011, respectively, primarily related to the increased natural gas purchase commitments made in accordance with PECO’s PAPUC-approved procurement schedule.

•

PECO’s other purchase obligations, which primarily represent commitments for services, materials and information increased $115 million for 2009, $14 million for 2010 through 2011 and $2 million for 2012 through 2013.

•

See Note 14 of the Combined Notes to Consolidated Financial Statements for further information on the Registrants’ commitments.

EXELON GENERATION COMPANY

General

Generation operates in a single business segment and its operations consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to Generation’s results of operations for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 and six months ended June 30, 2009 compared to the six months ended June 30, 2008 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If

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these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to revolving credit facilities of $4.8 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.

See the “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q for further discussion.

Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

Cash Flows from Operating Activities

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to Generation’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to Generation’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

COMMONWEALTH EDISON COMPANY

General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.

Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

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Results of Operations

A discussion of items pertinent to ComEd’s results of operations for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 and six months ended June 30, 2009 compared to the six months ended June 30, 2008 is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to its revolving credit facility. At June 30, 2009, ComEd had access to a revolving credit facility with aggregate bank commitments of $952 million.

See the “EXELON CORPORATION — Liquidity and Capital Resources” and Note 7 of the Combined Notes to the Financial Statements of this Form 10-Q for further discussion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to Exelon’s pension plans. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. ComEd paid a dividend of $120 million on its common stock during the first six months of 2009. To manage its cash flows and its capital structure, ComEd did not pay a dividend in 2008.

Cash Flows from Operating Activities

A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to ComEd’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to ComEd’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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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 the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in Pennsylvania in the counties surrounding the City of Philadelphia.

Executive Overview

A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to PECO’s results of operations for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 and six months ended June 30, 2009 compared to the six months ended June 30, 2008 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations, and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At June 30, 2009, PECO had access to a revolving credit facility with aggregate bank commitments of $574 million.

See “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q 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. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

Cash Flows from Operating Activities

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

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Item 3.

Quantitative and Qualitative Disclosures About Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, 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 risk management activities.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)

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, natural gas, coal and emission allowances. Within Exelon, Generation has the most exposure to commodity price risk. PECO has transferred substantially all of its near term electricity commodity price risk to Generation through a purchase power agreement (PPA) that expires at the end of 2010. PECO’s commodity price risk following the expiration of its generation rate caps and the PPA is addressed by its PAPUC-approved Default Service Program (DSP Program), which allows for full cost recovery and has a 29-month term that expires on May 31, 2013. As a mechanism to reduce commodity price risk relating to natural gas, PECO has implemented a natural gas procurement policy that is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. ComEd has transferred most of its near term commodity price risk to generating companies through the ICC approved procurement processes and a significant portion of its longer term commodity price risk to Generation through the five-year financial swap contract that expires on May 31, 2013. The Illinois Settlement Legislation provides for the pass-through of procurement costs by ComEd to its customers.

Generation

Generation’s energy contracts are accounted for under SFAS No. 133. Economic hedges may qualify for the normal purchases and normal sales exception to SFAS No. 133 which is discussed in Critical Accounting Policies and Estimates. Economic hedges that do not qualify for the normal purchases and normal sales exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in results of operations unless specific hedge accounting criteria are met and the derivatives are designated as cash-flow hedges, in which case changes in fair value are recorded in other comprehensive income (OCI), and gains and losses are recognized in results of operations 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 results of operations.

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 financial derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2009 through 2011 and the ComEd financial swap contract during 2009 through 2013.

The economic hedge activity resulted in a net mark to market energy contract asset position, excluding the rights of offset for derivative instruments subject to master netting agreements and the application of collateral in

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accordance with FSP FIN 39-1, of $2,881 million at June 30, 2009, comprised of a net energy contract asset for cash flow hedges of $2,519 million and a net energy contract asset for other derivatives of $362 million. The net mark to market asset position for the portfolio at June 30, 2009 is a result of forward market prices decreasing relative to the contracted price of the derivative instruments, the majority of which are hedges of future power sales. Activity associated with the cash flow hedges are recognized through accumulated OCI until the period in which the associated physical sale of power occurs. At that time, the cash flow hedge’s mark-to-market position is reversed and reclassified as results of operations, which when combined with the impacts of the actual physical power sale, results in the ultimate recognition of net revenues at the contracted price.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2009, the percentage of expected generation hedged was 95% - 98%, 87% - 90%, and 59% - 62% for 2009, 2010 and 2011, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. During peak periods, Generation’s amount hedged declines to meet its energy and capacity commitments to ComEd and PECO. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price exposure for Generation’s non-trading portfolio associated with a $5 reduction in the annual average Ni-Hub and PJM-West around-the-clock energy price based on June 30, 2009 market conditions and hedged position would be a decrease in pre-tax net income of approximately $5 million, $70 million and $360 million, respectively, for 2009, 2010 and 2011. Power prices sensitivities are derived by adjusting the power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

Proprietary Trading Activities. Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of 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. The proprietary trading activities, which included volumes of 2,003 gigawatt hours (GWhs) and 4,334 GWhs for the three and six months ended June 30, 2009 and 1,784 GWhs and 3,646 GWhs for the three and six months ended June 30, 2008, respectively. Trading portfolio activity for the six months ended June 30, 2009 resulted in pre-tax gains of $3 million due to net mark-to-market losses of $40 million and realized gains of $43 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its Value-at-Risk (VaR). The daily VaR on proprietary trading activity averaged $210,000 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, 2009 of $3,404 million, Generation has not segregated proprietary trading activity in the following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and VaR limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s Risk Management Committee monitor the financial risks of the proprietary trading activities.

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ComEd

ComEd’s energy contracts are accounted for under SFAS No. 133 and qualify for the normal purchases and normal sales exception to SFAS No. 133. The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd will be entitled to receive full cost recovery in rates. The change in fair value each period is recorded by ComEd as a regulatory asset or liability.

The contracts that ComEd has entered into as part of the initial ComEd auction and the RFP contracts are deemed to be derivatives that qualify for the normal purchases and normal sales exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivatives.

PECO

Generation and PECO have entered into a long-term full-requirements PPA under which PECO obtains all of its electric supply from Generation through 2010. The PPA is not considered a derivative under SFAS No. 133, in accordance with the terms of the agreement. Pursuant to the PECO’s PAPUC-approved DSP Program, PECO began to procure electric generation in June 2009. PECO has entered into forward purchase energy block (block contracts) and full requirements fixed price contracts to procure electric generation for its residential procurement class. The full requirements contracts qualify for the normal purchases and normal sales scope exception to SFAS No. 133. The block contracts qualify as derivatives under SFAS No. 133. PECO records the fair value of these block contracts on its balance sheet. However, since these block contracts were executed in accordance with the PAPUC-approved DSP Program and PECO will receive full cost recovery in rates, PECO did not elect hedge accounting and the change in fair value is recorded by PECO as a regulatory asset or liability. As of June 30, 2009, PECO’s mark-to-market position related to its forward purchase energy block contracts (block contracts) was not significant. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivatives.

PECO has also entered into derivative natural gas contracts to hedge its long-term price risk in the natural gas market. All of PECO’s natural gas supply agreements that are derivatives qualify for the normal purchases and normal sales exception to SFAS No. 133.

Trading and Non-Trading Marketing Activities. The following detailed presentation of Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s and ComEd’s mark-to-market net asset or liability balance sheet position from January 1, 2009 to June 30, 2009. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets. This table excludes all normal purchases and normal sales contracts.


	Generation			ComEd			Intercompany Eliminations(e)			Exelon
Total mark-to-market energy contract net assets (liabilities) at December 31, 2008(a)	$	1,118		$	(456	)	$	—		$	662
Total change in fair value of contracts recorded in result of operations		43			—			—			43
Reclassification to realized at settlement of contracts recorded in results of operations		(63	)		—			—			(63	)
Ineffective portion recognized in income		(8	)		—			—			(8	)
Reclassification to realized at settlement from accumulated OCI(b)		(674	)		—			86			(588	)
Effective portion of changes in fair value—recorded in OCI(c)(f)		1,766			—			(667	)		1,099
Changes in fair value—energy derivatives related to utility procurement(d)		—			(581	)		581			—
Changes in collateral		(247	)		—			—			(247	)
Other balance sheet reclassifications		15			—			—			15

Total mark-to-market energy contract net assets (liabilities) at June 30, 2009(a)	$	1,950		$	(1,037	)	$	—		$	913

(a)	Amounts are shown net of collateral paid to and received from counterparties in accordance with FSP FIN 39-1.

(b)	For Generation, includes $86 million loss of reclassifications from accumulated OCI to net income for the six months ended June 30, 2009 related to the settlement of the five-year financial swap contract with ComEd.

(c)	For Generation, includes $667 million gain of changes in fair value of the five-year financial swap with ComEd for the six months ended June 30, 2009.

(d)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of June 30, 2009, ComEd recorded a $1,037 million regulatory asset related to its mark-to-market derivative liability. In addition, ComEd included additional purchased power expense of $86 million related to changes in fair value of the five-year swap contract with Generation for the six months ended June 30, 2009.

(e)	Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation.

(f)	For Generation, includes $8 million of changes in cash flow hedge ineffectiveness, of which none was related to Generation’s financial swap contract with ComEd.

The following tables detail the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2009 and December 31, 2008 in accordance with FSP FIN 39-1:


	June 30, 2009
	Generation(a)(b)			ComEd(a)			Intercompany Elimination(c)			Exelon
Current assets	$	912		$	—		$	(285	)	$	627
Noncurrent assets		1,405			—			(753	)		652

Total mark-to-market energy contract assets		2,317			—			(1,038	)		1,279

Current liabilities		(294	)		(285	)		285			(294	)
Noncurrent liabilities		(73	)		(752	)		753			(72	)

Total mark-to-market energy contract liabilities		(367	)		(1,037	)		1,038			(366	)

Total mark-to-market energy contract net assets (liabilities)	$	1,950		$	(1,037	)	$	—		$	913

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(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $285 million and $752 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract.

(b)

In accordance with FSP FIN 39-1, current and noncurrent assets are shown net of collateral of $247 million and $280 million, respectively, and current and noncurrent liabilities are shown net of collateral of $425 million and $48 million, respectively. The total cash collateral received net of cash collateral posted was $1,000 million at June 30, 2009.

(c)	Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation.


	December 31, 2008
	Generation(a)(b)			ComEd(a)			Intercompany Elimination(c)			Exelon
Current assets	$	521		$	—		$	(111	)	$	410
Noncurrent assets		835			—			(345	)		490

Total mark-to-market energy contract assets		1,356			—			(456	)		900

Current liabilities		(214	)		(111	)		111			(214	)
Noncurrent liabilities		(24	)		(345	)		345			(24	)

Total mark-to-market energy contract liabilities		(238	)		(456	)		456			(238	)

Total mark-to-market energy contract net assets (liabilities)	$	1,118		$	(456	)	$	—		$	662

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $111 million and $345 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract.

(b)

In accordance with FSP FIN 39-1, current and noncurrent assets are shown net of collateral of $177 million and $252 million, respectively, and current and noncurrent liabilities are shown net of collateral of $274 million and $50 million, respectively. The total cash collateral received net of cash collateral posted was $753 million at December 31, 2008.

(c)	Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation.

Fair Values

The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask mid-point prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available vary by commodity, region and product. The remainder of the contracts, which are primarily option contracts, represents contracts for which external valuations are not available. These contracts are valued using the Black model, an industry standard option valuation model.

The fair values reflect the level of forward prices and volatility factors as of June 30, 2009 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts Generation and ComEd hold and sell. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from the swap between Generation and ComEd, energy marketing, trading activities and such variations could be material. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further information regarding valuation.

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The following tables, which present maturity and source of fair value of mark-to-market energy contract net assets (liabilities), provides two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market asset or (liability). Second, the tables provide the maturity, by year, of the Registrants’ net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash.

Exelon


	Maturities Within																Total Fair Value
	2009			2010			2011			2012			2013		2014 and Beyond		Total Fair Value
Normal Operations, qualifying cash-flow hedge contracts(a)(c):
Prices provided by external sources	$	442		$	444		$	196		$	24		$	4	$	—	$	1,110
Prices based on model or other valuation methods		1			—			7			13			—		—		21

Total	$	443		$	444		$	203		$	37		$	4	$	—	$	1,131

Normal Operations, other derivative contracts(b)(c):
Actively quoted prices	$	2		$	(2	)	$	—		$	—		$	—	$	—	$	—
Prices provided by external sources		(377	)		64			107			(5	)		—		—		(211	)
Prices based on model or other valuation methods		26			(21	)		(3	)		(9	)		—		—		(7	)

Total	$	(349	)	$	41		$	104		$	(14	)	$	—	$	—	$	(218	)

(a)	Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in OCI. Excludes $1,037 million gain associated with the five-year financial swap with ComEd.

(b)	Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash-flow hedges are recorded in results of operations.

(c)	Amounts are shown net of collateral paid to and received from counterparties in accordance with FSP FIN 39-1.

Generation


	Maturities Within																Total Fair Value
	2009			2010			2011			2012			2013		2014 and Beyond		Total Fair Value
Normal Operations, qualifying cash-flow hedge contracts(a)(c):
Prices provided by external sources	$	442		$	444		$	196		$	24		$	4	$	—	$	1,110
Prices based on model or other valuation methods		158			293			293			248			66		—		1,058

Total	$	600		$	737		$	489		$	272		$	70	$	—	$	2,168

Normal Operations, other derivative contracts(b)(c):
Actively quoted prices	$	2		$	(2	)	$	—		$	—		$	—	$	—	$	—
Prices provided by external sources		(377	)		64			107			(5	)		—		—		(211	)
Prices based on model or other valuation methods		26			(21	)		(3	)		(9	)		—		—		(7	)

Total	$	(349	)	$	41		$	104		$	(14	)	$	—	$	—	$	(218	)

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(a)	Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in OCI. Includes $1,037 million gain associated with the five-year financial swap with ComEd.

(b)	Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash-flow hedges are recorded in results of operations.

(c)	Amounts are shown net of collateral paid to and received from counterparties in accordance with FSP FIN 39-1.

ComEd


	Maturities Within															Total Fair Value
	2009			2010			2011			2012			2013			Total Fair Value
Prices based on model or other valuation methods(a)	$	(157	)	$	(293	)	$	(286	)	$	(235	)	$	(66	)	$	(1,037	)

(a)	Represents ComEd’s net liabilities associated with the five-year financial swap with Generation.

Cash-Flow Hedges

The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of June 30, 2009. 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, 2009 to June 30, 2009, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges).


Six Months Ended June 30, 2009	Income Statement Location	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2008		$	855	(a)	$	585
Effective portion of changes in fair value			1,059	(b)		654
Reclassifications from accumulated OCI to net income	Operating Revenue		(407	)(c)		(354	)
Ineffective portion recognized in income	Purchased Power		5			5

Accumulated OCI derivative gain at June 30, 2009		$	1,512	(a)	$	890

(a)	Includes $624 million and $275 million gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2009 and December 31, 2008, respectively.

(b)	Includes $401 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2009.

(c)	Includes $52 million loss, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2009.

Credit Risk (Exelon, Generation, ComEd and PECO)

Generation

In September 2006, Generation participated in and won portions of the ComEd and Ameren electricity supply auctions. Beginning in 2007 and as a result of the auctions, Generation’s sales to counterparties other than ComEd and PECO increased due to the expiration of the PPA with ComEd on December 31, 2006. Illinois Settlement Legislation passed during 2007 established a new procurement process in place of the procurement auctions. Generation participated in the 2008 ComEd RFP procurement process and will continue to have credit risk in connection with contracts for sale of electricity resulting from the ICC-approved competitive procurement

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process. Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment; therefore, Generation’s credit risk profile has changed based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. For additional information on the Illinois auction and the various regulatory proceedings, see Note 3 of the Combined Notes to Consolidated Financial Statements.

Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, the credit department establishes margining thresholds and collateral requirements for each counterparty, which are defined in each contract. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. See the Collateral section below for additional information.

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2009. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through Regional Transmission Organizations (RTOs), Independent System Operators (ISOs) and New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE) commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $115 million and $181 million, respectively. See Note 17 – Related-Party Transactions for further information.


Rating as of June 30, 2009	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number Of Counterparties Greater than 10% of Net Exposure	Net Exposure Of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,585	$	540	$	1,045	1	$	113
Non-investment grade		7		6		1	—		—
No external ratings
Internally rated — investment grade		1		—		1	—		—
Internally rated — non-investment grade		32		6		26	—		—

Total	$	1,625	$	552	$	1,073	1	$	113


	Maturity of Credit Risk Exposure
Rating as of June 30, 2009	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,277	$	308	$	—	$	1,585
Non-investment grade		7		—		—		7
No external ratings
Internally rated — investment grade		1		—		—		1
Internally rated — non-investment grade		22		10		—		32

Total	$	1,307	$	318	$	—	$	1,625

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Net Credit Exposure by Type of Counterparty	As of June 30, 2009
Financial institutions	$	415
Investor-owned utilities, marketers and power producers		578
Coal		3
Other		77

Total	$	1,073

ComEd

Credit risk for ComEd is managed by credit and collection policies, which are consistent with state regulatory requirements. ComEd is currently obligated to provide service to all electric customers within their franchised territories. ComEd records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. ComEd will continue to monitor the impact of the September 2008 rate increase on its customer payment practices as it relates to its provision for uncollectible accounts. ComEd will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. The Illinois Settlement Legislation prohibits utilities, including ComEd, from terminating electric service to a residential electric space heat customer due to nonpayment between December 1 of any year through March 1 of the following year. ComEd will monitor the impact of its disconnection practices and will make any necessary adjustments to the provision for uncollectible accounts. ComEd did not have any customers representing over 10% of its revenues as of June 30, 2009.

PECO

Credit risk for PECO is managed by credit and collection policies, which are consistent with state regulatory requirements. PECO is currently obligated to provide service to all retail electric customers within its franchised territories. PECO records a provision for uncollectible accounts, primarily based upon historical experience, to provide for the potential loss from nonpayment by these customers. In accordance with PAPUC regulations, after November 30 and before April 1, an electric distribution utility or natural gas distribution utility shall not terminate service to customers with household incomes at or below 250% of the Federal poverty level. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in PAPUC regulations. PECO did not have any customers representing over 10% of its revenues as of June 30, 2009.

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assets, PPAs and other market sources at prices that are currently below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act. As noted under Item 1A. Risk Factors, PECO could be negatively affected if Generation could not perform under the PPA.

PECO’s supplier master agreements that govern the terms of its default service program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the current forward price curve for energy compared to the initial market price, the forward price of energy on the day a transaction is executed. If the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2009, PECO had no credit exposure to suppliers under its electric procurement contracts, as the initial market price was greater than market prices.

PECO does not obtain collateral from suppliers under its natural gas supply agreements. As of June 30, 2009, PECO has no credit exposure under its natural gas supply contracts as the fixed-contract obligation costs are greater than projected market prices.

Collateral (Generation, ComEd and PECO)

Generation

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

Generation sells output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Exelon depends on access to bank credit lines which serve as liquidity sources to fund collateral requirements. Since the banking industry issues started to surface in mid-2007, credit markets have tightened. Exelon will be required to renew most of its credit facilities in the 2011-2012 timeframe. The cost and availability to renew may be substantially different than when Exelon originally negotiated the existing liquidity facilities.

As of June 30, 2009, Generation had $136 million of cash collateral deposit payments being held by counterparties and Generation was holding $1,139 million of cash collateral deposits received from counterparties. $1,000 million of net cash collateral deposits received net of deposits made was offset against mark-to-market assets and liabilities, in accordance with FSP FIN 39-1. See Note 14 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

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ComEd

Beginning in 2007, under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd, collateral postings will be one-sided from Generation only. Therefore, if market prices fall below ComEd’s benchmark price levels, ComEd is not required to post collateral; however, if market prices rise above the benchmark price levels with ComEd, Generation may be required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the 5-year financial swap contract with ComEd, there are no immediate collateral provisions on either party. However, the swap contract also provides that: (1) if ComEd is downgraded below investment grade by Moody’s or S&P, or (2) if Generation is downgraded below investment grade by Moody’s or S& P, collateral postings would be required by the applicable party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. As of June 30, 2009, there was no cash collateral or letters of credit posted between any suppliers, including Generation, and ComEd associated with the supplier forward contracts.

Illinois Settlement Legislation passed during 2007 established a new procurement process in place of the procurement auctions. Beginning in June 2009, under the terms of ComEd’s standard block energy contracts, collateral postings are only required from the supplier, including Generation, should exposures between market prices and benchmark prices exceed unsecured credit limits outlined in the agreement. The terms of ComEd’s procurement contracts provide that collateral requirements of the suppliers are affected by their security ratings. As stipulated in the Illinois Settlement Legislation as well as the ICC-approved procurement tariff, ComEd is permitted to recover its costs of procuring power and energy plus any prudent costs that a utility incurs in arranging and providing for the supply of electric power and energy. Thus all costs associated with collateral postings are recoverable from retail customers through ComEd’s procurement tariff. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

PECO

In October 2008, S&P downgraded PECO’s credit rating to BBB from BBB+. As a result, PECO was required to provide PJM $90 million in collateral in the form of a letter of credit. On February 26, 2009, PECO, Generation, and PJM entered into an agreement, based on changes to the way PECO and Generation administer their PPA for default service that enabled PECO’s collateral requirement to PJM to be reduced from $90 million to $5 million. On May 13, 2009, a remeasurement of the collateral requirement under the PJM policy indicated no collateral was required and the $5 million letter of credit was cancelled. If PECO lost its investment grade credit rating as of June 30, 2009, it would have been required to provide collateral of $4 million pursuant to PJM’s credit policy.

PECO’s supplier master agreements that govern the terms of its default service program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that require PECO to post collateral. This collateral may be posted in the form of cash or credit support with threshold’s contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2009, PECO could have been required to provide collateral of approximately $48 million related to its natural gas procurement contracts, which is well within its current available credit facility capacity of $564 million. As of June 30, 2009, PECO was not required to post any additional collateral for any of these agreements.

RTOs and ISOs.

Generation, ComEd and PECO participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, New York ISO, MISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and

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sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.

Exchange Traded Transactions.

Generation enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearinghouse acts as the counterparty to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX and ICE are significantly collateralized and have limited counterparty credit risk.

Generation and PECO

Fuel Procurement. Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term contracts for uranium concentrates, and long-term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2009 through 2013 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See Note 14 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

PECO procures natural gas from suppliers under both short-term and long-term contracts. PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply agreements and block and full requirements contracts is mitigated by its ability to recover its natural gas costs through the PAPUC purchased gas cost clause that allows PECO to adjust rates quarterly to reflect realized natural gas prices.

Exelon

Exelon’s consolidated balance sheets, as of June 30, 2009, included a $589 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 $1.5 billion, less unearned income of $902 million. The future minimum lease payments by lessees are supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases.

Interest-Rate Risk (Exelon, Generation and ComEd)

The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants may also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of

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capital. At June 30, 2009, Exelon had $100 million of notional amounts of fair-value hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than $1 million decrease in Exelon’s, Generation’s and ComEd’s pre-tax earnings for the three months ended June 30, 2009.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of June 30, 2009, 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 $339 million reduction in the fair value of the trust assets. See Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of equity price risk as a result of the current capital and credit market conditions.

In addition, Exelon and Generation maintain trust assets associated with defined benefit pension and other postretirement benefits. Actual asset returns on those assets have a significant effect on the costs reported for Exelon’s pension and postretirement benefit plans. The overall actual asset returns across the Registrant’s pension and postretirement benefit plans through June 30, 2009 were approximately 5.0% and 5.9%, respectively. If the pension and postretirement assets return an annual rate of 8.50% for the rest of the year, the 2009 actual return on the pension and postretirement assets would be 9.4% and 10.1%, respectively, compared to an expected long-term return assumption of positive 8.5% and 8.1%, respectively. Those return levels would impact 2010 and 2011 benefit costs as follows:


	Decrease in 2010 Pension Cost			Decrease in 2010 Postretirement Benefit Cost			Increase in 2011 Pension Cost		Decrease in 2011 Postretirement Benefit Cost
2009 asset returns for pension and postretirement benefits of 9.4% and 10.1%, respectively	$	(1	)	$	(4	)	$	2	$	(4	)

This information assumes that movements in asset returns occur absent changes to other actuarial assumptions, and does not consider any actions management may take to mitigate the impact of the asset return shortfalls, such as changes to the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential increase in benefit costs set forth above. Asset returns may also have a significant impact on the 2009 year-end balance sheet. If the actual 2009 asset returns for pension and postretirement benefits were 9.4% and 10.1%, respectively for pension and postretirement assets, Exelon’s OCI (shareholders’ equity) would be reduced by approximately $81 million upon remeasurement of plan assets and obligations at December 31.

Changes in discount rates may have the effect of offsetting these changes in costs and OCI upon the remeasurement of the plan at December 31. Increases in actual discount rates, absent other changes in other assumptions, decrease pension and postretirement costs and obligations. Discount rate assumption sensitivities are discussed in Critical Accounting Policies and Estimates within Exelon’s 2008 Annual Report on Form 10-K.

Generation, ComEd and PECO account for their participation in Exelon’s pension and other postretirement benefit plans by applying multiemployer accounting pursuant to SFAS No. 87 and SFAS No 106. Exelon allocates the components of pension and other postretirement costs as well as contributions to the participating employers based on several factors, including the measures of active employee participation in each participating unit.

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Item 4.

Controls and Procedures

During the second quarter of 2009, Exelon’s management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by Exelon to ensure that (a) material information relating to Exelon, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of Exelon and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2009, the principal executive officer and principal financial officer of Exelon concluded that Exelon’s disclosure controls and procedures were effective to accomplish its objectives. Exelon continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2009 that have materially affected, or are reasonably likely to materially affect, Exelon’s internal control over financial reporting.

Item 4T.

Controls and Procedures

During the second quarter of 2009, each of Generation’s, ComEd’s and PECO’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each of Generation, ComEd and PECO to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2009, the principal executive officer and principal financial officer of each of Generation, ComEd and PECO concluded that such registrant’s disclosure controls and procedures were effective to accomplish its objectives. Generation, ComEd and PECO each continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2009 that have materially affected, or are reasonably likely to materially affect, each of Generation’s, ComEd’s and PECO’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.

Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. Legal Proceedings of the Registrants’ 2008 Annual Report on Form 10-K and (b) Notes 3 and 14 of the Combined Notes to Consolidated Financial Statements in Part I, Item 1 of this Report. Such descriptions are incorporated herein by these references.

Item 1A.

Risk Factors

At June 30, 2009, the Registrants’ risk factors changed compared to the risk factors described in Exelon’s 2008 Annual Report on Form 10-K in that the risk factors under the heading “Proposed Acquisition of NRG” are no longer applicable as Exelon terminated its efforts to acquire NRG on July 21, 2009.

Item 4.

Submission of Matters to a Vote of Security Holders

Exelon

Exelon held its 2008 Annual Meeting of Shareholders on April 28, 2009.

Proposal 1 was the election of ten Class II and Class III directors to serve a one-year term expiring in 2010. The following directors were elected:


	Votes For	Votes Against	Votes Abstaining
Class II Directors
John A. Canning, Jr.	484,378,029	11,830,038	1,968,883
M. Walter D’Alessio	445,097,086	51,021,932	2,057,832
Bruce DeMars	484,235,574	11,915,466	2,025,811
Nelson A. Diaz	458,762,927	37,417,659	1,996,264
Rosemarie B. Greco	477,440,456	18,699,687	2,036,706
Paul L. Joskow	470,549,232	25,656,261	1,971,464
John M. Palms	480,498,160	15,583,789	2,094,907
John W. Rogers, Jr.	467,785,047	28,222,350	2,154,253
John W. Rowe	476,283,837	19,945,446	1,947,667
Stephen D. Steinour	481,429,389	14,694,135	2,053,425

The Class I directors whose terms of office continued after the meeting with three-year terms expiring in 2010 were: Nicholas DeBenedictis, Sue L. Gin, Richard W. Mies, William C. Richardson, Thomas J. Ridge, and Don Thompson.

Proposal 2 was the renewal of the Exelon Corporation Annual Incentive Plan for Senior Executives, Effective January 1, 2009. The shareholders approved the proposal with a vote of 399,119,819 votes cast for, 17,756,558 votes cast against, 1,761,744 votes abstaining and 79,539,335 broker non-votes.

Proposal 3 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2009. The shareholders approved the proposal with a vote of 490,821,802 votes cast for, 5,868,565 votes cast against and 1,487,082 votes abstaining.

Proposal 4 was a shareholder proposal to develop a report showing whether Exelon’s actions to reduce global warming have reduced mean global temperature or avoided disasters. The proposal was defeated with a vote of 13,713,246 votes cast for and 333,653,314 votes cast against. There were also 71,273,111 votes abstaining and 79,537,785 broker non-votes.

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Item 6.

Exhibits


Exhibit No.		Description
3-1		PECO Energy Company Amended Bylaws (File 000-16844, Form 8-K dated May 6, 2009, Exhibit 99.1)

4-1		One Hundredth and Seventh Supplemental Indenture dated as of March 15, 2009 from PECO to U.S. Bank National Association, as trustee (File 000-16844, Form 8-K dated March 26, 2009, Exhibit 4.1)

101.INS*		XBRL Instance

101.SCH*		XBRL Taxonomy Extension Schema

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Labels

101.PRE*		XBRL Taxonomy Extension Presentation

*	XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 filed by the following officers for the following companies:



31-1		— Filed by John W. Rowe for Exelon Corporation

31-2		— Filed by Matthew F. Hilzinger for Exelon Corporation

31-3		— Filed by John W. Rowe for Exelon Generation Company, LLC

31-4		— Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC

31-5		— Filed by Frank M. Clark for Commonwealth Edison Company

31-6		— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

31-7		— Filed by Denis P. O’Brien for PECO Energy Company

31-8		— Filed by Phillip S. Barnett for PECO Energy Company

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 filed by the following officers for the following companies:



32-1		— Filed by John W. Rowe for Exelon Corporation

32-2		— Filed by Matthew F. Hilzinger for Exelon Corporation

32-3		— Filed by John W. Rowe for Exelon Generation Company, LLC

32-4		— Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC

32-5		— Filed by Frank M. Clark for Commonwealth Edison Company

32-6		— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

32-7		— Filed by Denis P. O’Brien for PECO Energy Company

32-8		— Filed by Phillip S. Barnett for PECO Energy Company

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION


/s/ JOHN W. ROWE		/s/ MATTHEW F. HILZINGER
John W. Rowe		Matthew F. Hilzinger
Chairman and Chief Executive Officer (Principal Executive Officer)		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ DUANE M. DESPARTE
Duane M. DesParte
Vice President and Corporate Controller (Principal Accounting Officer)

July 24, 2009

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC


/s/ JOHN W. ROWE		/s/ MATTHEW F. HILZINGER
John W. Rowe		Matthew F. Hilzinger
Chairman (Principal Executive Officer)		(Principal Financial Officer)

/s/ JON D. VEURINK
Jon D. Veurink
Vice President and Controller (Principal Accounting Officer)

July 24, 2009

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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.

COMMONWEALTH EDISON COMPANY


/s/ FRANK M. CLARK		/s/ ANNE R. PRAMAGGIORE
Frank M. Clark		Anne R. Pramaggiore
Chairman and Chief Executive Officer (Principal Executive Officer)		President and Chief Operating Officer

/s/ JOSEPH R. TRPIK, JR.		/s/ MATTHEW R. GALVANONI
Joseph R. Trpik, Jr.		Matthew R. Galvanoni
Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)		Vice President and Controller (Principal Accounting Officer)

July 24, 2009

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/ DENIS P. O’BRIEN		/s/ PHILLIP S. BARNETT
Denis P. O’Brien		Phillip S. Barnett
Chief Executive Officer and President (Principal Executive Officer)		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW R. GALVANONI
Matthew R. Galvanoni
Vice President and Controller (Principal Accounting Officer)

July 24, 2009

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