Edgar Filing: EXELON GENERATION CO LLC

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 September 30, 2010

¨	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
	(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

Exelon Generation Company, LLC

Commonwealth Edison Company

PECO Energy Company

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 September 30, 2010 was:


Exelon Corporation Common Stock, without par value		661,413,334
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			5

FORWARD-LOOKING STATEMENTS			5

WHERE TO FIND MORE INFORMATION			5

PART I.	FINANCIAL INFORMATION		6

ITEM 1.	FINANCIAL STATEMENTS		6

	Exelon Corporation		7

	Consolidated Statements of Operations and Comprehensive Income		7

	Consolidated Statements of Cash Flows		8

	Consolidated Balance Sheets		9

	Consolidated Statement of Changes in Shareholders’ Equity		11

	Exelon Generation Company, LLC		12

	Consolidated Statements of Operations and Comprehensive Income		12

	Consolidated Statements of Cash Flows		13

	Consolidated Balance Sheets		14

	Consolidated Statement of Changes in Equity		16

	Commonwealth Edison Company		17

	Consolidated Statements of Operations and Comprehensive Income		17

	Consolidated Statements of Cash Flows		18

	Consolidated Balance Sheets		19

	Consolidated Statement of Changes in Shareholders’ Equity		21

	PECO Energy Company		22

	Consolidated Statements of Operations and Comprehensive Income		22

	Consolidated Statements of Cash Flows		23

	Consolidated Balance Sheets		24

	Consolidated Statement of Changes in Shareholders’ Equity		26

	Combined Notes to Consolidated Financial Statements		27

	1. Basis of Presentation		27

	2. New Accounting Pronouncements		30

	3. Regulatory Matters		31

	4. Acquisitions		39

	5. Fair Value of Financial Assets and Liabilities		40

	6. Debt and Credit Agreements		58

	7. Derivative Financial Instruments		61

	8. Retirement Benefits		75

	9. Corporate Restructuring and Plant Retirements		78

	10. Income Taxes		81

	11. Nuclear Decommissioning		86


		Page No.

	12. Earnings Per Share and Equity		89

	13. Commitments and Contingencies		90

	14. Supplemental Financial Information		101

	15. Segment Information		106

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		109

	Exelon Corporation		109

	General		109

	Executive Overview		109

	Critical Accounting Policies and Estimates		120

	Results of Operations		121

	Liquidity and Capital Resources		142

	Exelon Generation Company, LLC		151

	Commonwealth Edison Company		152

	PECO Energy Company		154

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		156

ITEM 4.	CONTROLS AND PROCEDURES		164

ITEM 4T.	CONTROLS AND PROCEDURES		164

PART II.	OTHER INFORMATION		166

ITEM 1.	LEGAL PROCEEDINGS		166

ITEM 1A.	RISK FACTORS		166

ITEM 6.	EXHIBITS		166

SIGNATURES			168

	Exelon Corporation		168

	Exelon Generation Company, LLC		168

	Commonwealth Edison Company		169

	PECO Energy Company		169

CERTIFICATION EXHIBITS			170

	Exelon Corporation		170, 178

	Exelon Generation Company, LLC		172, 180

	Commonwealth Edison Company		174, 182

	PECO Energy Company		176, 184


GLOSSARY OF TERMS AND ABBREVIATIONS

Exelon Corporation and Related Entities
Exelon		Exelon Corporation
Generation		Exelon Generation Company, LLC
ComEd		Commonwealth Edison Company
PECO		PECO Energy Company
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon’s holding company
Exelon Transmission Company		Exelon Transmission Company, LLC
AmerGen		AmerGen Energy Company, LLC
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
PETT		PECO Energy Transition Trust
Registrants		Exelon, Generation, ComEd, and PECO, collectively

Other Terms and Abbreviations
Note “ ” of the 2009 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2009 Annual Report on Form 10-K
1998 Restructuring Settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit
AEPS Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARRA		American Recovery and Reinvestment Act of 2009
Block Contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAMR		Federal Clean Air Mercury Rule
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
CTC		Competitive Transition Charge
DOE		U.S. Department of Energy
DSP Program		Default Service Provider Program
EE&C		Energy Efficiency and Conservation/Demand
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GWh		Gigawatt hour
HAP		Hazardous Air Pollutants
Health Care Reform Acts		Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010
ICC		Illinois Commerce Commission
ICE		Intercontinental Exchange
Illinois Act		Illinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
IPA		Illinois Power Agency


Other Terms and Abbreviations
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
JDR		John Deere Renewables, LLC
LIBOR		London Interbank Offered Rate
LLRW		Low-Level Radioactive Waste
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standards
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NJDEP		New Jersey Department of Environmental Protection
Non-Regulatory Agreement Units		Former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOV		Notice of Violation
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OPEB		Other Postretirement Employee Benefits
PA DEP		Pennsylvania Department of Environmental Protection
PAPUC		Pennsylvania Public Utility Commission
PCCA		Pennsylvania Climate Change Act
PGC		Purchased Gas Cost Clause
PJM		PJM Interconnection, LLC
PPA		Power Purchase Agreement
Prescription Drug Act		Medicare Prescription Drug Improvement and Modernization Drug Act of 2003
PRP		Potentially Responsible Party
PSEG		Public Service Enterprise Group Incorporated
PURTA		Pennsylvania Public Utility Realty Tax Act
REC		Renewable Energy Credit
RFP		Request for Proposal
RMC		Risk Management Committee
RPS		Renewable Energy Portfolio Standards
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
Regulatory Agreement Units		Former ComEd and former PECO nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
SFC		Supplier Forward Contract
SGIG		Smart Grid Investment Grant
SILO		Sale-In, Lease-Out
SNF		Spent Nuclear Fuel
VIE		Variable Interest Entity

FILING FORMAT

This combined Form 10-Q is being filed separately by 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’ 2009 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 13 of this Report; and (b) other factors discussed herein and in other filings with the 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 September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2010			2009			2010			2009
Operating revenues	$	5,291		$	4,339		$	14,150		$	13,202
Operating expenses
Purchased power		1,481			796			3,273			2,400
Fuel		475			404			1,469			1,640
Operating and maintenance		1,122			1,020			3,298			3,492
Operating and maintenance for regulatory required programs		37			19			98			44
Depreciation and amortization		578			485			1,611			1,360
Taxes other than income		232			212			615			592

Total operating expenses		3,925			2,936			10,364			9,528

Operating income		1,366			1,403			3,786			3,674

Other income and deductions
Interest expense		(169	)		(170	)		(615	)		(493	)
Interest expense to affiliates, net		(6	)		(18	)		(19	)		(62	)
Loss in equity method investments		—			(8	)		—			(21	)
Other, net		206			148			178			367

Total other income and deductions		31			(48	)		(456	)		(209	)

Income before income taxes		1,397			1,355			3,330			3,465
Income taxes		552			598			1,291			1,339

Net income		845			757			2,039			2,126

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		3			(3	)		(8	)		(8	)
Actuarial loss reclassified to periodic cost		24			26			86			72
Transition obligation reclassified to periodic cost		—			1			5			2
Pension and non-pension postretirement benefit plans valuation adjustment		2			—			(18	)		28
Change in unrealized gain (loss) on cash flow hedges		222			(128	)		196			177
Change in unrealized gain on marketable securities		—			2			—			7

Other comprehensive income (loss)		251			(102	)		261			278

Comprehensive income	$	1,096		$	655		$	2,300		$	2,404

Average shares of common stock outstanding:
Basic		662			660			661			659
Diluted		663			662			662			661

Earnings per average common share:
Basic	$	1.28		$	1.15		$	3.08		$	3.22
Diluted	$	1.27		$	1.14		$	3.08		$	3.21

Dividends per common share	$	0.53		$	0.53		$	1.58		$	1.58

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2010			2009
Cash flows from operating activities
Net income	$	2,039		$	2,126
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,255			1,935
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		240			740
Net fair value changes related to derivatives		(281	)		(74	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(49	)		(183	)
Other non-cash operating activities		468			464
Changes in assets and liabilities:
Accounts receivable		(172	)		335
Inventories		(52	)		41
Accounts payable, accrued expenses and other current liabilities		(53	)		(591	)
Option premiums paid, net		(101	)		(39	)
Counterparty collateral received, net		289			380
Income taxes		310			(176	)
Pension and non-pension postretirement benefit contributions		(740	)		(456	)
Other assets and liabilities		(41	)		(96	)

Net cash flows provided by operating activities		4,112			4,629

Cash flows from investing activities
Capital expenditures		(2,382	)		(2,252	)
Proceeds from nuclear decommissioning trust fund sales		21,869			18,769
Investment in nuclear decommissioning trust funds		(21,977	)		(18,949	)
Change in restricted cash		427			32
Other investing activities		26			16

Net cash flows used in investing activities		(2,037	)		(2,384	)

Cash flows from financing activities
Changes in short-term debt		(90	)		(71	)
Issuance of long-term debt		1,398			1,987
Retirement of long-term debt		(827	)		(1,515	)
Retirement of long-term debt of variable interest entity		(806	)		—
Retirement of long-term debt to financing affiliates		—			(533	)
Dividends paid on common stock		(1,042	)		(1,038	)
Proceeds from employee stock plans		34			28
Other financing activities		(17	)		—

Net cash flows used in financing activities		(1,350	)		(1,142	)

Increase in cash and cash equivalents		725			1,103
Cash and cash equivalents at beginning of period		2,010			1,271

Cash and cash equivalents at end of period	$	2,735		$	2,374

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	2,735	$	2,010
Restricted cash and investments		26		40
Accounts receivable, net
Customer ($393 gross accounts receivable pledged as collateral as of September 30, 2010)		1,816		1,563
Other		464		486
Mark-to-market derivative assets		522		376
Inventories, net
Fossil fuel		222		198
Materials and supplies		587		559
Other		388		209

Total current assets		6,760		5,441

Property, plant and equipment, net		28,554		27,341
Deferred debits and other assets
Regulatory assets		4,058		4,872
Nuclear decommissioning trust funds		6,147		6,669
Investments		713		704
Investments in affiliates		15		20
Goodwill		2,625		2,625
Mark-to-market derivative assets		671		649
Pledged assets for Zion Station decommissioning		801		—
Other		604		859

Total deferred debits and other assets		15,634		16,398

Total assets	$	50,948	$	49,180

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010			December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	65		$	155
Short-term notes payable — accounts receivable agreement		225			—
Long-term debt due within one year		553			639
Long-term debt to PECO Energy Transition Trust due within one year		—			415
Accounts payable		1,056			1,345
Accrued expenses		1,203			923
Deferred income taxes		204			152
Mark-to-market derivative liabilities		67			198
Other		594			411

Total current liabilities		3,967			4,238

Long-term debt		11,662			10,995
Long-term debt to financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		6,153			5,750
Asset retirement obligations		3,243			3,434
Pension obligations		2,919			3,625
Non-pension postretirement benefit obligations		2,336			2,180
Spent nuclear fuel obligation		1,018			1,017
Regulatory liabilities		3,440			3,492
Mark-to-market derivative liabilities		8			23
Payable for Zion Station decommissioning		667			—
Other		1,103			1,309

Total deferred credits and other liabilities		20,887			20,830

Total liabilities		36,906			36,453

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 661 and 660 shares outstanding at September 30, 2010 and December 31, 2009, respectively)		8,982			8,923
Treasury stock, at cost (35 and 35 shares held at September 30, 2010 and December 31, 2009, respectively)		(2,327	)		(2,328	)
Retained earnings		9,128			8,134
Accumulated other comprehensive loss, net		(1,828	)		(2,089	)

Total shareholders’ equity		13,955			12,640

Total liabilities and shareholders’ equity	$	50,948		$	49,180

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions, shares in thousands)	Issued Shares		Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Total Shareholders’ Equity
Balance, December 31, 2009		694,565	$	8,923	$	(2,328	)	$	8,134		$	(2,089	)	$	12,640
Net income		—		—		—			2,039			—			2,039
Long-term incentive plan activity		1,591		59		1			(1	)		—			59
Common stock dividends		—		—		—			(1,044	)		—			(1,044	)
Other comprehensive income, net of income taxes of $171		—		—		—			—			261			261

Balance, September 30, 2010		696,156	$	8,982	$	(2,327	)	$	9,128		$	(1,828	)	$	13,955

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 September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
Operating revenues
Operating revenues	$	1,877		$	1,534		$	5,098		$	4,737
Operating revenues from affiliates		778			911			2,330			2,687

Total operating revenues		2,655			2,445			7,428			7,424

Operating expenses
Purchased power		494			303			1,251			962
Fuel		451			379			1,191			1,295
Operating and maintenance		580			522			1,865			1,975
Operating and maintenance from affiliates		69			70			216			235
Depreciation and amortization		121			74			344			223
Taxes other than income		57			51			175			150

Total operating expenses		1,772			1,399			5,042			4,840

Operating income		883			1,046			2,386			2,584

Other income and deductions
Interest expense		(37	)		(24	)		(109	)		(77	)
Loss in equity method investments		—			(1	)		—			(2	)
Other, net		192			192			138			325

Total other income and deductions		155			167			29			246

Income before income taxes		1,038			1,213			2,415			2,830
Income taxes		433			556			867			1,133

Net income		605			657			1,548			1,697

Other comprehensive income (loss), net of income taxes
Change in unrealized gain (loss) on cash flow hedges		292			(98	)		298			559

Other comprehensive income (loss)		292			(98	)		298			559

Comprehensive income	$	897		$	559		$	1,846		$	2,256

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2010			2009
Cash flows from operating activities
Net income	$	1,548		$	1,697
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		987			797
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		409			674
Net fair value changes related to derivatives		(281	)		(74	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(49	)		(183	)
Other non-cash operating activities		164			29
Changes in assets and liabilities:
Accounts receivable		(11	)		147
Receivables from and payables to affiliates, net		76			(30	)
Inventories		(50	)		(8	)
Accounts payable, accrued expenses and other current liabilities		(162	)		(233	)
Option premiums paid, net		(101	)		(39	)
Counterparty collateral received, net		443			379
Income taxes		(13	)		(22	)
Pension and non-pension postretirement benefit contributions		(345	)		(208	)
Other assets and liabilities		(52	)		6

Net cash flows provided by operating activities		2,563			3,155

Cash flows from investing activities
Capital expenditures		(1,405	)		(1,330	)
Proceeds from nuclear decommissioning trust fund sales		21,869			18,769
Investment in nuclear decommissioning trust funds		(21,977	)		(18,949	)
Change in restricted cash		3			14
Other investing activities		9			(1	)

Net cash flows used in investing activities		(1,501	)		(1,497	)

Cash flows from financing activities
Issuance of long-term debt		898			1,546
Retirement of long-term debt		(214	)		(920	)
Distribution to member		(623	)		(1,800	)
Contribution from member		3			58
Other financing activities		(16	)		(2	)

Net cash flows provided by (used in) financing activities		48			(1,118	)

Increase in cash and cash equivalents		1,110			540
Cash and cash equivalents at beginning of period		1,099			1,135

Cash and cash equivalents at end of period	$	2,209		$	1,675

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	2,209	$	1,099
Restricted cash and cash equivalents		2		5
Accounts receivable, net
Customer		398		495
Other		220		112
Mark-to-market derivative assets		522		376
Mark-to-market derivative assets with affiliates		479		302
Receivables from affiliates		216		297
Inventories, net
Fossil fuel		128		102
Materials and supplies		495		470
Other		148		102

Total current assets		4,817		3,360

Property, plant and equipment, net		10,542		9,809
Deferred debits and other assets
Nuclear decommissioning trust funds		6,147		6,669
Investments		37		46
Mark-to-market derivative assets		654		639
Mark-to-market derivative assets with affiliates		653		671
Prepaid pension asset		1,261		1,027
Pledged assets for Zion Station decommissioning		801		—
Other		138		185

Total deferred debits and other assets		9,691		9,237

Total assets	$	25,050	$	22,406

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
LIABILITIES AND EQUITY
Current liabilities
Long-term debt due within one year	$	552	$	26
Accounts payable		567		826
Accrued expenses		636		670
Payables to affiliates		39		80
Deferred income taxes		582		399
Mark-to-market derivative liabilities		64		198
Other		152		63

Total current liabilities		2,592		2,262

Long-term debt		3,125		2,967
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		3,117		2,707
Asset retirement obligations		3,123		3,316
Non-pension postretirement benefit obligations		751		659
Spent nuclear fuel obligation		1,018		1,017
Payables to affiliates		2,132		2,228
Mark-to-market derivative liabilities		7		21
Payable for Zion Station decommissioning		667		—
Other		500		437

Total deferred credits and other liabilities		11,315		10,385

Total liabilities		17,032		15,614

Commitments and contingencies
Equity
Member’s equity
Membership interest		3,467		3,464
Undistributed earnings		3,094		2,169
Accumulated other comprehensive income, net		1,455		1,157

Total member’s equity		8,016		6,790
Noncontrolling interest		2		2

Total equity		8,018		6,792

Total liabilities and equity	$	25,050	$	22,406

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
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income, net		Noncontrolling Interest		Total Equity
Balance, December 31, 2009	$	3,464	$	2,169		$	1,157	$	2	$	6,792
Net income		—		1,548			—		—		1,548
Allocation of tax benefit from member		3		—			—		—		3
Distribution to member		—		(623	)		—		—		(623	)
Other comprehensive income, net of income taxes of $184		—		—			298		—		298

Balance, September 30, 2010	$	3,467	$	3,094		$	1,455	$	2	$	8,018

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 September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
Operating revenues
Operating revenues	$	1,918		$	1,474		$	4,831		$	4,415
Operating revenues from affiliates		—			1			1			2

Total operating revenues		1,918			1,475			4,832			4,417

Operating expenses
Purchased power		910			423			1,810			1,235
Purchased power from affiliate		202			353			826			1,138
Operating and maintenance		260			234			620			668
Operating and maintenance from affiliate		38			39			113			128
Operating and maintenance for regulatory required programs		22			19			62			44
Depreciation and amortization		126			125			386			371
Taxes other than income		81			79			188			215

Total operating expenses		1,639			1,272			4,005			3,799

Operating income		279			203			827			618

Other income and deductions
Interest expense		(79	)		(79	)		(290	)		(231	)
Interest expense to affiliates, net		(3	)		(3	)		(10	)		(10	)
Other, net		3			(19	)		14			67

Total other income and deductions		(79	)		(101	)		(286	)		(174	)

Income before income taxes		200			102			541			444
Income taxes		79			56			295			169

Net income		121			46			246			275

Other comprehensive income, net of income taxes
Change in unrealized loss on cash flow hedges		4			—			—			—
Change in unrealized gain on marketable securities		—			2			—			7

Other comprehensive income		4			2			—			7

Comprehensive income	$	125		$	48		$	246		$	282

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2010			2009
Cash flows from operating activities
Net income	$	246		$	275
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		387			372
Deferred income taxes and amortization of investment tax credits		199			205
Other non-cash operating activities		162			235
Changes in assets and liabilities:
Accounts receivable		(72	)		102
Receivables from and payables to affiliates, net		(69	)		(43	)
Inventories		(2	)		3
Accounts payable, accrued expenses and other current liabilities		224			(172	)
Counterparty collateral (posted) received, net		(154	)		1
Income taxes		61			(84	)
Pension and non-pension postretirement benefit contributions		(254	)		(161	)
Other assets and liabilities		(86	)		(22	)

Net cash flows provided by operating activities		642			711

Cash flows from investing activities
Capital expenditures		(686	)		(605	)
Other investing activities		16			14

Net cash flows used in investing activities		(670	)		(591	)

Cash flows from financing activities
Changes in short-term debt		(90	)		80
Issuance of long-term debt		500			191
Retirement of long-term debt		(213	)		(208	)
Contributions from parent		2			8
Dividends paid on common stock		(225	)		(180	)
Other financing activities		(3	)		—

Net cash flows used in financing activities		(29	)		(109	)

Increase (decrease) in cash and cash equivalents		(57	)		11
Cash and cash equivalents at beginning of period		91			47

Cash and cash equivalents at end of period	$	34		$	58

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	34	$	91
Restricted cash and cash equivalents		—		2
Accounts receivable, net
Customer		794		676
Other		113		318
Inventories, net		73		71
Regulatory assets		476		358
Deferred income taxes		157		39
Counterparty collateral deposited		153		—
Other		15		24

Total current assets		1,815		1,579

Property, plant and equipment, net		12,429		12,125
Deferred debits and other assets
Regulatory assets		1,096		1,096
Investments		23		28
Investments in affiliates		6		6
Goodwill		2,625		2,625
Receivables from affiliates		1,794		1,920
Prepaid pension asset		1,066		907
Other		447		411

Total deferred debits and other assets		7,057		6,993

Total assets	$	21,301	$	20,697

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	65	$	155
Long-term debt due within one year		1		213
Accounts payable		279		274
Accrued expenses		516		282
Payables to affiliates		82		177
Customer deposits		128		131
Regulatory liabilities		106		11
Mark-to-market derivative liability with affiliate		476		302
Other		47		52

Total current liabilities		1,700		1,597

Long-term debt		5,000		4,498
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,968		2,648
Asset retirement obligations		96		95
Non-pension postretirement benefits obligations		307		241
Regulatory liabilities		3,060		3,145
Mark-to-market derivative liability with affiliate		651		669
Other		408		716

Total deferred credits and other liabilities		7,490		7,514

Total liabilities		14,396		13,815

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		4,992		4,990
Retained earnings		325		304

Total shareholders’ equity		6,905		6,882

Total liabilities and shareholders’ equity	$	21,301	$	20,697

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 Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2009	$	1,588	$	4,990	$	(1,639	)	$	1,943		$	6,882
Net income		—		—		246			—			246
Allocation of tax benefit from parent		—		2		—			—			2
Appropriation of retained earnings for future dividends		—		—		(246	)		246			—
Common stock dividends		—		—		—			(225	)		(225	)

Balance, September 30, 2010	$	1,588	$	4,992	$	(1,639	)	$	1,964		$	6,905

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 September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
Operating revenues
Operating revenues	$	1,494		$	1,325		$	4,216		$	4,038
Operating revenues from affiliates		1			2			4			7

Total operating revenues		1,495			1,327			4,220			4,045

Operating expenses
Purchased power		76			70			211			203
Purchased power from affiliate		574			555			1,498			1,539
Fuel		23			26			278			346
Operating and maintenance		155			132			440			409
Operating and maintenance from affiliates		21			22			67			72
Operating and maintenance for regulatory required programs		15			—			36			—
Depreciation and amortization		326			272			859			726
Taxes other than income		90			78			240			213

Total operating expenses		1,280			1,155			3,629			3,508

Operating income		215			172			591			537

Other income and deductions
Interest expense		(35	)		(32	)		(151	)		(93	)
Interest expense to affiliates, net		(3	)		(14	)		(9	)		(52	)
Loss in equity method investments		—			(6	)		—			(19	)
Other, net		3			2			6			8

Total other income and deductions		(35	)		(50	)		(154	)		(156	)

Income before income taxes		180			122			437			381
Income taxes		53			30			134			106

Net income		127			92			303			275
Preferred security dividends		1			1			3			3

Net income on common stock		126			91			300			272

Comprehensive income, net of income taxes
Net income		127			92			303			275
Other comprehensive loss, net of income taxes
Amortization of realized loss on settled cash flow swaps		—			(1	)		(1	)		(1	)

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

Comprehensive income	$	127		$	91		$	302		$	274

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2010			2009
Cash flows from operating activities
Net income	$	303		$	275
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		859			726
Deferred income taxes and amortization of investment tax credits		(405	)		(166	)
Other non-cash operating activities		85			107
Changes in assets and liabilities:
Accounts receivable		(104	)		86
Receivables from and payables to affiliates, net		(12	)		32
Inventories		2			47
Accounts payable, accrued expenses and other current liabilities		(20	)		(154	)
Income taxes		243			27
Pension and non-pension postretirement benefit contributions		(68	)		(41	)
Other assets and liabilities		36			(77	)

Net cash flows provided by operating activities		919			862

Cash flows from investing activities
Capital expenditures		(358	)		(267	)
Change in restricted cash		412			2
Other investing activities		7			2

Net cash flows provided by (used in) investing activities		61			(263	)

Cash flows from financing activities
Changes in short-term debt		—			(95	)
Issuance of long-term debt		—			250
Retirement of long-term debt of variable interest entity		(806	)		—
Retirement of long-term debt to PECO Energy Transition Trust		—			(533	)
Dividends paid on common stock		(178	)		(247	)
Dividends paid on preferred securities		(3	)		(3	)
Repayment of receivable from parent		135			240
Contributions from parent		1			27

Net cash flows used in financing activities		(851	)		(361	)

Increase in cash and cash equivalents		129			238
Cash and cash equivalents at beginning of period		303			39

Cash and cash equivalents at end of period	$	432		$	277

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010		December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	432	$	303
Restricted cash and cash equivalents		2		1
Accounts receivable, net
Customer ($393 gross accounts receivable pledged as collateral as of September 30, 2010)		624		392
Other		121		120
Inventories, net
Fossil fuel		94		96
Materials and supplies		18		18
Deferred income taxes		21		65
Prepaid utility taxes		31		—
Other		31		11

Total current assets		1,374		1,006

Property, plant and equipment, net		5,502		5,297
Deferred debits and other assets
Regulatory assets		1,124		1,834
Investments		20		18
Investments in affiliates		8		13
Receivable from affiliates		341		311
Prepaid pension asset		281		225
Other		65		315

Total deferred debits and other assets		1,839		2,716

Total assets	$	8,715	$	9,019

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	September 30, 2010			December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term notes payable — accounts receivable agreement	$	225		$	—
Long-term debt to PECO Energy Transition Trust due within one year		—			415
Accounts payable		138			164
Accrued expenses		92			74
Payables to affiliates		177			189
Customer deposits		65			65
Mark-to-market derivative liabilities		3			—
Mark-to-market derivative liabilities with affiliate		3			—
Other		36			32

Total current liabilities		739			939

Long-term debt		2,222			2,221
Long-term debt to financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,802			2,241
Asset retirement obligations		24			24
Non-pension postretirement benefits obligations		319			296
Regulatory liabilities		380			317
Mark-to-market derivative liabilities		1			2
Mark-to-market derivative liabilities with affiliate		2			2
Other		133			141

Total deferred credits and other liabilities		2,661			3,023

Total liabilities		5,806			6,367

Commitments and contingencies
Preferred securities		87			87
Shareholders’ equity
Common stock		2,319			2,318
Receivable from parent		(45	)		(180	)
Retained earnings		548			426
Accumulated other comprehensive income, net		—			1

Total shareholders’ equity		2,822			2,565

Total liabilities and shareholders’ equity	$	8,715		$	9,019

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, net			Total Shareholders’ Equity
Balance, December 31, 2009	$	2,318	$	(180	)	$	426		$	1		$	2,565
Net income		—		—			303			—			303
Common stock dividends		—		—			(178	)		—			(178	)
Preferred security dividends		—		—			(3	)		—			(3	)
Repayment of receivable from parent		—		135			—			—			135
Allocation of tax benefit from parent		1		—			—			—			1
Other comprehensive loss, net of income taxes of $1		—		—			—			(1	)		(1	)

Balance, September 30, 2010	$	2,319	$	(45	)	$	548		$	—		$	2,822

See the Combined Notes to Consolidated Financial Statements

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 is a utility services holding company engaged, through its principal subsidiaries, in the energy 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 Generation. The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by 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.

Through its business services subsidiary, BSC, Exelon provides its 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 Combined Notes to 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 Exelon SHC, LLC, of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon and is eliminated in Exelon’s consolidated financial statements, 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 September 30, 2010, as equity, and PECO’s preferred securities as preferred securities of subsidiary in its Consolidated Financial Statements.

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 the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a 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 or cost method of accounting.

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 September 30, 2010 and 2009 and for the three and nine months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO, include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2009 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in Exelon’s, Generation’s and ComEd’s Consolidated Statements of Cash Flows and in ComEd’s and PECO’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect Exelon’s, Generation’s or ComEd’s cash flows from operating activities or ComEd’s and PECO’s financial position. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 2009 Annual Report on Form 10-K.

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

Under the applicable authoritative guidance, VIEs are legal entities that possess any of the following characteristics: an insufficient amount of equity at risk to finance their activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns significant to the VIE. Companies are required to consolidate a VIE if they are its primary beneficiary.

Generation

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in Nuclear Electric Insurance Limited are discussed in further detail in Note 18 of the 2009 Form 10-K. Generation has evaluated these contracts and determined that either it has no variable interest in an entity or, where Generation does have a variable interest in an entity, it is not the primary beneficiary and, therefore, consolidation is not required.

Several of Generation’s long-term PPAs have been determined to be operating leases that have no residual value guarantees, bargain purchase options or other provisions that would cause these operating leases to be variable interests and, therefore, not subject to this guidance. For contracts where Generation has a variable interest, Generation has considered which interest holder has the power to direct the activities that most significantly impact the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities, which provides the operator with the power to direct the VIEs’ activities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities, under the contracts Generation receives less than the majority of the output of the remaining expected useful life of the facilities, and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 13 — Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required.

Generation has aggregated its contracts with VIEs into two categories, energy commitments and fuel purchase obligations, based on the similar risk characteristics and significance to Generation. As of the balance sheet date, the carrying amount of assets and liabilities in Generation’s Consolidated Balance Sheet that relate to its involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Generation for the deliveries associated with the current billing cycle under the contracts. Further, Generation has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of its involvement with the VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Generation has entered into an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 11 — Nuclear Decommissioning. Generation has evaluated this agreement and determined that it has variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required.

ComEd and PECO

ComEd’s retail operations include the purchase of electricity and RECs through procurement contracts of varying durations. PECO’s retail operations include the purchase of electricity, AECs and natural gas through procurement contracts of varying durations. These contracts are discussed in further detail in Notes 2 and 18 of the 2009 Form 10-K. ComEd and PECO have evaluated these contracts and determined that either they have no variable interest in a VIE or where ComEd or PECO do have a variable interest in a VIE as described below, they are not the primary beneficiary and, therefore, consolidation is not required.

For contracts where ComEd or PECO have a variable interest, consideration has been given to which interest holder has the power to direct the activities that most significantly impact the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd and PECO do not have control over the operation and maintenance of the entities considered VIEs and they do not bear operational risk related to their activities. Furthermore, ComEd and PECO have no debt or equity investments in the VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 13 — Commitments and Contingencies. Accordingly, ComEd and PECO do not consider themselves to be the primary beneficiary of these VIEs.

As of the balance sheet date, the carrying amounts of assets and liabilities in ComEd’s and PECO’s Consolidated Balance Sheet that relate to their involvement with these VIEs are predominately related to working capital accounts and generally represent the amounts owed by ComEd and PECO for the purchases associated with the current billing cycle under the contracts.

The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s, ComEd’s or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO have concluded that they do not have a variable interest in ComEd Financing III, PECO Trust III or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. ComEd and PECO, as the sponsors of the financing trusts, are obligated to pay the operating expenses of the trusts.

PECO

PETT, a financing trust, was created in 1998 by PECO to purchase and own Intangible Transition Property (ITP) and to issue transition bonds to securitize $5 billion of PECO’s stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PECO made an initial capital contribution of $25 million to PETT. ITP represents the irrevocable right of PECO to collect intangible transition charges (ITC). ITC consists of the portion of CTCs that were sold by PECO to PETT and securitized through the various issuances of PETT’s transition bonds from 1999 through 2001 as authorized by the PAPUC and provides PETT with an asset sufficient to recover the aggregate principal amount of the transition bonds issued, plus amounts sufficient to provide for the credit enhancement, interest payments, servicing fees and other expenses relating to the transition bonds. PETT’s assets were restricted for the sole purpose of satisfying PETT’s obligation to its transition bondholders and payment of various administrative fees as outlined in the transition bond transaction documents.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

PECO does not provide ongoing financial support to PETT or guarantee PETT’s performance, and the transition bondholders do not have recourse to PECO. PECO had continuing involvement in PETT in its role as the servicer of the ITC collections, for which PECO received a fee. During the three and nine months ended September 30, 2010, net pre-tax losses of $4 million and $16 million, respectively, related to PETT’s results of operations are reflected in PECO’s Consolidated Statements of Operations.

PETT was consolidated in Exelon’s and PECO’s financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective on that date. Under previously issued authoritative guidance, PETT was deconsolidated in accordance with a prescribed quantitative approach, based on expected losses, of identifying the primary beneficiary. PECO has concluded that it is the primary beneficiary of PETT due to PECO’s involvement in the design of PETT, its role as servicer of the ITC collections, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT’s other expenses. The consolidation of PETT did not have a significant impact on PECO’s results of operations or statement of cash flows. Upon retirement of the outstanding transition bonds on September 1, 2010, the remaining cash balance was remitted to PECO, and PETT was dissolved on September 20, 2010. During the three and nine months ended September 30, 2010, PECO recognized interest expense on PETT’s transition bonds of $4 million and $22 million, respectively, which is reflected in PECO’s Consolidated Statements of Operations. See Note 6 — Debt and Credit Agreements for further information regarding PETT’s debt to bondholders.

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

The Registrants adopted the following recently issued accounting standards:

Transfers of Financial Assets

In June 2009, the FASB issued authoritative guidance amending the accounting for transfers of financial assets. This guidance was effective and applied prospectively for the Registrants beginning January 1, 2010. The impact of the adoption for Exelon and PECO and relevant disclosure are included in Note 6 — Debt and Credit Agreements. The adoption of this guidance did not impact Generation’s or ComEd’s results of operations, cash flows or financial positions.

Consolidation of Variable Interest Entities

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance became effective for the Registrants on January 1, 2010. The impact of the adoption for Exelon and PECO and relevant disclosure are included in Note 1 — Basis of Presentation. The adoption of this guidance did not impact Generation’s or ComEd’s results of operations, cash flows or financial positions.

Fair Value Measurements Disclosures

In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers. Additionally, the guidance clarifies that a reporting entity should provide

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). Currently, the Registrants’ mark-to-market derivative assets and liabilities and NDT fund investments are the only fair value measurements affected by this guidance. This guidance became effective for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation, which will be effective for interim and annual periods beginning after December 15, 2010. As this guidance provides only additional disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 5 — Fair Value of Financial Assets and Liabilities for additional information.

The following recently issued accounting standards are not yet reflected in the combined consolidated financial statements of the Registrants:

Revenue Arrangements with Multiple Deliverables

In October 2009, the FASB issued authoritative guidance that amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. The guidance is expected to result in more multiple-deliverable arrangements being separable than under current guidance. This guidance is effective for the Registrants beginning on January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The Registrants are currently assessing the effects this guidance may have on their consolidated financial statements.

Credit Quality of Financing Receivables and Allowance for Credit Losses Disclosures

In July 2010, the FASB issued authoritative guidance requiring entities to disclose additional information about their allowance for credit losses and the credit quality of their financing receivables, including the nature of the credit risk inherent in their financing receivables portfolio, how the risk is analyzed and assessed in determining the allowance for credit losses, and the changes and reasons for changes in the allowance for credit losses. This guidance is effective for the Registrants as of December 31, 2010. As this guidance provides only additional disclosure requirements, the adoption of this standard will not impact the Registrants’ results of operations, cash flows or financial positions.

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

Regulatory and Legislative Proceedings (Exelon, Generation, ComEd and PECO)

Except for the matters noted below, the disclosures set forth in Note 2 of the 2009 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Settlement Agreement (Exelon, Generation and ComEd). Various Illinois electric utilities, their affiliates and generators of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years ending in 2010 to programs to provide rate relief to Illinois electricity customers and funding for the IPA, created as a result of the Illinois Settlement Legislation. Generation recognized net costs from its contributions pursuant to the Illinois Settlement Legislation of $5 million and $14 million for the three and nine months ended September 30, 2010 and $14 million and $78 million for the three and nine months ended September 30, 2009, respectively, in its Consolidated Statements of Operations. ComEd’s net costs from its contributions pursuant to the Illinois Settlement Legislation were $0 and $1 million for the three and nine months ended September 30, 2010, respectively, and $3 million and $6 million for the three and nine months ended September 30, 2009, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

As of September 30, 2010, Generation’s remaining costs to be recognized related to the rate relief commitment are $6 million, consisting of $2 million related to programs for ComEd customers and $4 million for programs for customers of other Illinois utilities. ComEd has no remaining costs to be recognized related to the rate relief commitment as of September 30, 2010.

Illinois Procurement Proceedings (Exelon and ComEd). Under the Illinois Settlement Legislation, ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. With the approval of the ICC, the IPA administers a competitive process under which ComEd procures its electricity supply based on ComEd’s anticipated supply needs.

On April 30, 2010, the ICC approved the results of ComEd’s 2010 energy procurement RFP process. Approximately 25% and 6% of ComEd’s expected energy requirements for the June 2010 through May 2011 period and the June 2011 through May 2012 period, respectively, are being procured through the 2010 RFP process. The remainder of ComEd’s expected energy requirements through May 2012 will be met through additional Block Contracts resulting from previously completed and future RFP processes or purchased through the spot market and hedged by the financial swap contract with Generation.

The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On May 24, 2010, the ICC approved the results of ComEd’s 2010 RFP to procure RECs for the period June 2010 through May 2011. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s energy commitments.

Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electric distribution rate case approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of accumulated post-test year depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). On October 21, 2010, ComEd filed a petition for rehearing with the Court in connection with the September 30, 2010 ruling.

The Court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period (the same position ComEd has taken in its 2010 electric distribution rate case discussed below). The Court’s ruling, absent reversal following further proceedings, may trigger a refund obligation. The ICC will ultimately be required to set a just and reasonable rate which will determine the amount of refund. The impact on ComEd’s rates and any associated refund obligation should be prospective from no earlier than the date of the Court’s ruling on September 30, 2010. ComEd will continue to bill rates as established under the ICC’s order in the 2007 electric distribution rate case, but will recognize for accounting purposes its estimate of any refund obligation, subject to true-up when the ICC establishes a new rate. An interest charge may accrue on any refund amount. ComEd estimates the refund obligation could be as much as $18 million for the remainder of 2010.

The Court also reversed the ICC’s approval of ComEd’s Rider SMP, a program which included the installation of 131,000 smart meters in the Chicago area. The Court held that the ICC’s approval of Rider SMP constituted illegal single-issue ratemaking. The Court’s decision prescribes a new, more stringent standard for cost-recovery riders not specifically authorized by statute. Such riders would be allowed only if: (1) the pass-through cost is imposed by an “external circumstance” and is unexpected, volatile, or fluctuating; and (2) recovery via rider does not change other expenses or increase utility income. As a result of the Court’s ruling on Rider SMP, ComEd reclassified $6 million of regulatory assets to property, plant and equipment for costs to early retire meters replaced with smart meters during ComEd’s AMI/Customer Applications pilot. This is

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

consistent with the composite method of depreciation and recovery of capitalized expenditures. During the third quarter of 2010, ComEd also recorded a $4 million (pre-tax) write-off of regulatory assets associated with operating and maintenance costs that were originally allowable under Rider SMP, as the costs can no longer be recovered from customers. ComEd does not believe any of its other riders are impacted by the Court’s ruling. On October 18, 2010, ComEd filed a proposed tariff with the ICC to allow it to recover, through inclusion in the 2010 Rate Case, certain program operating costs originally allowed under Rider SMP that would otherwise be unrecoverable due to the Court’s decision. ComEd has requested the ICC to act on the proposed tariff within the fourth quarter. The Rider SMP pilot program capital investment has already been included in rate base in the 2010 Rate Case. ComEd cannot predict the ICC’s decision in connection with the proposed tariff.

2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its annual service revenue requirement for electric distribution to allow ComEd to continue modernizing its electric delivery system and recover the costs of substantial investments made since its last rate filing in 2007 (2010 Rate Case). The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested rate of return on common equity is 11.5%. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric bill by approximately 7%. In addition, ComEd is requesting future recovery of certain amounts that were previously recorded as expense. If that request is approved, ComEd would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd would recognize a one-time benefit of up to $39 million (pre-tax) to reverse the prior charges. The requested increase also includes $22 million for increased uncollectible accounts expense. If the rate request is approved, the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff would be increased by $22 million. The Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case makes it highly unlikely that the ICC would decide the accumulated post-test year depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $396 million could be reduced by approximately $85 million as a result of this adjustment. The new electric distribution rates would take effect no later than June 2011 unless the effective date is delayed due to the actions resulting from the appeals discussed below. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve.

On August 26, 2010, the Illinois Attorney General and certain other intervenors filed separate motions with the ICC to dismiss the 2010 Rate Case on procedural grounds in connection with ComEd’s initial filing on June 30, 2010. On September 17, 2010, the ALJs in the case denied those motions to dismiss. On October 8, 2010, the Coalition to Request Equitable Allocation of Costs Together (REACT) appealed this decision to the ICC (Appeal). On October 15, 2010, ComEd filed with the ICC its opposition to the appeal filed by REACT. There is no specific time period for the ICC to act on the Appeal. The ICC could deny the Appeal or dismiss the 2010 Rate Case. The latter action would cause some delay in the effectiveness of rates that might otherwise become effective in June 2011. The extent of lost revenues for 2011 would depend upon the length of the delay and the amount of the rate increase ultimately approved by the ICC. ComEd cannot predict when the ICC will rule or how much of the requested electric distribution rate increase the ICC may approve. ComEd is continuing to evaluate it options in connection with the Appeal.

Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd). In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with the legislation, with minor modifications. As a result of that ICC order, ComEd recorded a regulatory asset of $70

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. Recovery of the regulatory asset associated with 2008 and 2009 activities will take place over an approximate 14-month time frame, which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund as required by the legislation. The fund is used to assist low-income residential customers.

Annual Transmission Formula Rate Update (Exelon and ComEd). ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s most recent annual formula rate update filed in May 2010 reflects actual 2009 expenses and investments plus forecasted 2010 capital additions. The update resulted in a revenue requirement of $430 million offset by a $14 million reduction related to the true-up of 2009 actual costs for a net revenue requirement of $416 million. This compares to the May 2009 updated net revenue requirement of $440 million. The decrease in the revenue requirement was primarily driven by ComEd’s 2009 cost savings measures. The 2010 net revenue requirement became effective June 1, 2010 and is recovered over the period extending through May 31, 2011. The regulatory liability associated with the true-up is being amortized as the associated revenues are refunded.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.27%, a decrease from the 9.43% return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 56%. This equity cap will be reduced to 55% in June 2011.

Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On March 31, 2010, PECO filed separate petitions before the PAPUC for increases of $316 million and $44 million to its annual service revenue requirement for electric and natural gas distribution, respectively, to fund critical infrastructure improvement projects to meet customer demand and ensure the safe and reliable delivery of electricity and natural gas. The requested rate of return on common equity under the electric and natural gas rate cases was 11.75%. On August 31, 2010, PECO and interested parties filed a joint petition for partial settlement with respect to PECO’s electric distribution rate case, and a joint petition for a full settlement with respect to PECO’s gas distribution rate case for increases in annual service revenue of $225 million and $20 million, respectively. The issue remaining for resolution in the electric distribution rate case is related to PECO’s Purchase of Electric Generation Supplier Receivables Program and does not impact the amount of the revenue requirement in the settlement. No overall rate of return on common equity was specified in the settlements. In addition, the settlements do not impact recoverability of PECO’s regulatory assets currently recorded and provides for recovery of PJM transmission service costs, on a current basis through an adjustable surcharge mechanism. The settlements are subject to PAPUC approval, and, if approved, the new electric and gas delivery rates will take effect on January 1, 2011.

Pennsylvania Transition-Related Regulatory Matters (Exelon, Generation and PECO). In 2009, the PAPUC entered an Order instituting an investigation into whether PECO’s nuclear decommissioning cost adjustment clause (NDCAC), which is a mechanism that allows PECO to recover costs from customers for the decommissioning of seven former PECO nuclear units now owned by Generation, should continue after December 31, 2010. During the course of the investigation, PECO and the interested parties reached an agreement, as set forth in a Stipulation and Joint Memorandum filed on February 24, 2010 (Settlement), that PECO is entitled to recover decommissioning costs through the NDCAC beyond December 31, 2010. The Settlement also contained a provision in which it was agreed that PECO would not claim recovery under the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

NDCAC for any incremental physical decommissioning costs incurred with respect to any former PECO nuclear unit as a result of an extension of that unit’s NRC Operating License. On July 15, 2010, the PAPUC approved the Settlement. See Note 11 — Nuclear Decommissioning for additional information.

Pennsylvania Procurement Proceedings (Exelon and PECO). In 2009, the PAPUC approved PECO’s DSP Program, under which PECO will provide default electric service following the expiration of its electric generation rate caps on December 31, 2010. Under the DSP Program, PECO is permitted to recover its electricity procurement costs from retail customers without mark-up through the generation supply adjustment (GSA) charged to default service customers. The GSA provides for the recovery of energy, capacity, ancillary and administrative costs and is subject to quarterly adjustments for any over or under collections. The filing and implementation costs of the DSP program have been recorded as a regulatory asset and are recoverable through the GSA over a 29-month period beginning in January 2011. On September 23, 2010, PECO entered into contracts with PAPUC-approved bidders for its fourth competitive procurement of electric supply for default electric service commencing January 2011, which included all customer classes. As of September 30, 2010, including the previous competitive procurements completed in 2009 and 2010, the 2011 expected energy requirements for all customer classes have been substantially procured. PECO will conduct 5 additional competitive procurements over the remainder of the term of the DSP Program, which expires May 31, 2013.

The hourly spot market price full requirements procurement tranches for large commercial and industrial default customers in the September 2010 procurement were not fully subscribed. PECO intends to serve the associated load through direct purchases from the PJM spot market and separately procured AEPS credits, for the period beginning January 1, 2011 through May 31, 2011. PECO will solicit bids for the unsubscribed hourly spot market price full requirements procurement tranches for its large commercial and industrial customer class in its next default service procurement occurring in May 2011.

As part of the 2009 settlement of the DSP Program, PECO filed a Revised Electric Purchase of Receivables (POR) program that requires PECO to purchase the customer accounts receivable of electric generation suppliers (EGS) that participate in the electric customer choice program and have elected consolidated billing under the 1998 Restructuring Settlement. The Revised Electric POR program was filed on November 20, 2009, and provided for full recovery of PECO’s system implementation costs for program administration through a temporary discount on purchased receivables. On June 16, 2010, the PAPUC approved PECO’s settlement of the electric POR program. The approved settlement states that PECO can terminate electric service to customers beginning January 1, 2011, based on unpaid charges for EGS service, and uncollectible accounts expense will be recovered from customers through distribution rates. As part of PECO’s electric distribution rate case settlement petition filed on August 31, 2010, the recovery mechanism for uncollectible accounts expense incurred on EGS receivables through distribution rates was disputed and is subject to further litigation before the PAPUC.

Smart Meter and Smart Grid Investments (Exelon and PECO). In 2009, PECO filed a joint petition with the PAPUC for partial settlement of its $550 million Smart Meter Procurement and Installation Plan to install more than 1.6 million smart meters and deploy advanced communication networks over a 15-year period. On April 22, 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan that provides for recovery through an adjustable surcharge mechanism of program expenses on a current basis and the accelerated depreciation incurred on existing meters due to early deployment over the period January 1, 2011 through December 31, 2020. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in October 2010 and for approval of a universal meter deployment plan for its remaining customers in 2012. As of September 30, 2010, PECO recorded regulatory assets related to recoverable program expenses, including accelerated depreciation on existing meters as shown in the Regulatory Assets and Liabilities table below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On April 12, 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project — Smart Future Greater Philadelphia. As a result of the SGIG funding, PECO will deploy 600,000 smart meters within three years, accelerate universal deployment of more than 1.6 million smart meters from 15 years to 10 years and increase smart grid investments to approximately $100 million over the next three years. The $200 million SGIG funds will be reimbursed ratably based on projected spending of more than $400 million, which includes approximately $7 million related to demonstration projects by two sub-recipients. The SGIG is non-taxable based on recent IRS guidance. The DOE has a conditional ownership interest in federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. In total, over the next 10 years, PECO is planning to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG from the DOE will be used to significantly reduce the impact of those investments on PECO ratepayers.

Energy Efficiency Program (Exelon and PECO). Pursuant to Act 129’s EE&C reduction targets, PECO filed its EE&C plan with the PAPUC and received partial approval in 2009. On February 11, 2010, the PAPUC approved PECO’s revisions to the EE&C plan. The approved four-year plan, which began on June 1, 2009, totals more than $330 million and is recoverable from ratepayers. As of September 30, 2010, PECO recorded a regulatory liability for revenue recognized, net of expenses incurred for the EE&C plan as shown in the Regulatory Assets and Liabilities tables below. During the three and nine months ended September 30, 2010, PECO recorded incurred operating expenses that were fully recovered from operating revenues related to the energy efficiency program as shown in the Operating and Maintenance for Regulatory Required Programs table below.

Alternative Energy Portfolio Standards (Exelon and PECO). PECO must comply with the AEPS Act after December 31, 2010. PECO has entered into five-year agreements with accepted bidders, including Generation, to purchase a total of 452,000 non-solar Tier I AECs annually, in order to prepare for 2011, PECO’s first year of required compliance. On March 3, 2010, PECO announced that it had entered into 10-year agreements to purchase 8,000 solar Tier 1 AECs annually. PECO also purchases AECs as part of its DSP Program full requirement procurements. The costs of AECs not purchased as part of the DSP Program full requirement procurements will be recovered from default service customers through an adjustable surcharge mechanism.

Regulatory Assets and Liabilities (Exelon, ComEd and PECO)

Exelon, ComEd and PECO prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of September 30, 2010 and December 31, 2009. For additional information on the specific regulatory assets and liabilities, refer to Note 19 of the 2009 Form 10-K.


September 30, 2010	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	156	$	—	$	156
Pension and other postretirement benefits		2,505		—		15
Deferred income taxes		856		23		833
Smart meter program expenses		12		—		12
Debt costs		129		113		16
Severance		79		79		—
Asset retirement obligations		66		50		16
MGP remediation costs		150		110		40
RTO start-up costs		10		10		—
Under-recovered uncollectible accounts		36		36		—
Financial swap with Generation — noncurrent		—		651		—
DSP Program electric procurement contracts — noncurrent(a)		1		—		3
DSP Program costs		7		—		7
Other		51		24		26

Noncurrent regulatory assets		4,058		1,096		1,124
Financial swap with Generation — current		—		476		—
DSP Program electric procurement contracts — current(a)		3		—		6

Total regulatory assets	$	4,061	$	1,572	$	1,130

Regulatory liabilities
Nuclear decommissioning(b)	$	2,133	$	1,792	$	341
Removal costs		1,236		1,236		—
Refund of PURTA taxes		4		—		4
Energy efficiency and demand response programs		66		32		34
Other		1		—		1

Noncurrent regulatory liabilities		3,440		3,060		380
Over-recovered energy and transmission costs current liability(c)		131		106		25

Total regulatory liabilities	$	3,571	$	3,166	$	405

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


December 31, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	883	$	—	$	883
Pension and other postretirement benefits		2,634		—		19
Deferred income taxes		842		20		822
Debt costs		144		125		19
Severance		95		95		—
Asset retirement obligations		65		49		16
MGP remediation costs		143		103		40
RTO start-up costs		12		12		—
Financial swap with Generation — noncurrent		—		669		—
DSP Program electric procurement contracts(a)		2		—		4
DSP Program costs		5		—		5
Other		47		23		26

Noncurrent regulatory assets		4,872		1,096		1,834
Financial swap with Generation — current		—		302		—
Under-recovered energy and transmission costs current asset		56		56		—

Total regulatory assets	$	4,928	$	1,454	$	1,834

Regulatory liabilities
Nuclear decommissioning(b)	$	2,229	$	1,918	$	311
Removal costs		1,212		1,212		—
Refund of PURTA taxes		4		—		4
Deferred taxes		30		—		—
Energy efficiency and demand response programs		15		15		—
Other		2		—		2

Noncurrent regulatory liabilities		3,492		3,145		317
Over-recovered energy and transmission costs current liability		33		11		22

Total regulatory liabilities	$	3,525	$	3,156	$	339

(a)

As of September 30, 2010 and December 31, 2009, PECO recorded a regulatory asset to offset the noncurrent mark-to-market liability recorded for derivative block contracts. PECO’s regulatory asset related to the current portion of its derivative liability for the DSP Program electric procurement contracts is included in other current assets in Exelon’s and PECO’s Consolidated Balance Sheets. See Note 7 — Derivative Financial Instruments for additional information.

(b)

These amounts represent estimated future nuclear decommissioning costs that are less than the associated NDT fund assets. These regulatory liabilities have an equal and offsetting noncurrent receivable from affiliate at ComEd and PECO, and a noncurrent payable to affiliate recorded at Generation equal to the total regulatory liability at Exelon, ComEd and PECO. See Note 11 — Nuclear Decommissioning for additional information on the NDT fund activity.

(c)	Over-recovered energy and transmission costs are included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Operating and Maintenance for Regulatory Required Programs (Exelon, ComEd and PECO)

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 ComEd and PECO for the three and nine months ended September 30, 2010 and 2009. An equal and offsetting amount has been reflected in operating revenues during the periods.


For the Three Months Ended September 30, 2010	Exelon		ComEd			PECO
Energy efficiency and demand response programs	$	35	$	21	(a)	$	14	(b)
Purchased power administrative costs		1		1			—
Consumer education program		1		—			1	(c)

Total operating and maintenance for regulatory required programs	$	37	$	22		$	15


For the Nine Months Ended September 30, 2010	Exelon		ComEd			PECO
Energy efficiency and demand response programs	$	93	$	59	(a)	$	34	(b)
Purchased power administrative costs		3		3			—
Consumer education program		2		—			2	(c)

Total operating and maintenance for regulatory required programs	$	98	$	62		$	36


For the Three Months Ended September 30, 2009	Exelon		ComEd			PECO
Energy efficiency and demand response programs	$	18	$	18	(a)	$	—
Purchased power administrative costs		1		1			—

Total operating and maintenance for regulatory required programs	$	19	$	19		$	—


For the Nine Months Ended September 30, 2009	Exelon		ComEd			PECO
Energy efficiency and demand response programs	$	41	$	41	(a)	$	—
Purchased power administrative costs		3		3			—

Total operating and maintenance for regulatory required programs	$	44	$	44		$	—

(a)	As a result of the Illinois Settlement Legislation, Illinois utilities are required to provide energy efficiency and demand response programs.

(b)	Represents recovered costs under PECO’s EE&C plan that was designed to meet Act 129’s energy efficiency and conservation/demand reduction targets.

(c)	In 2009, the PAPUC authorized PECO to collect a surcharge to recover expenditures associated with PECO’s approved consumer education plan related to the transition to competitive energy market prices.

4. Acquisitions (Exelon and Generation)

John Deere Renewables. On August 30, 2010, Generation entered into an agreement to acquire the equity interests of JDR, a leading operator and developer of wind power, for approximately $860 million. Under the terms of the agreement, Generation will acquire 735 MWs of installed, operating wind capacity located in eight states. Additionally, contingent upon the commencement of construction, Generation will pay approximately $40 million related to the three projects with a capacity of 230 MWs which are currently in advanced stages of development. The agreement is contingent upon antitrust clearance and Federal and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the fourth quarter of 2010. On September 30, 2010, Generation issued $900 million of senior notes whose proceeds will be used primarily to fund the anticipated acquisition. See Note 6 for additional information regarding the debt issuance. JDR is not expected to be a “significant subsidiary”, as defined by SEC financial statement reporting requirements, for Exelon or Generation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Non-Derivative Financial Assets and Liabilities. As of September 30, 2010 and December 31, 2009, the Registrants’ carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, short-term notes payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.

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 September 30, 2010 and December 31, 2009 were as follows:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	12,215	$	13,672	$	11,634	$	12,223
Long-term debt to PETT due within one year		—		—		415		426
Long-term debt to financing trusts		390		356		390		325
Spent nuclear fuel obligation		1,018		885		1,017		832
Preferred securities of subsidiary		87		72		87		63

Generation

The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligations as of September 30, 2010 and December 31, 2009 were as follows:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	3,677	$	4,018	$	2,993	$	3,132
Spent nuclear fuel obligation		1,018		885		1,017		832

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of September 30, 2010 and December 31, 2009 were as follows:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	5,001	$	5,757	$	4,711	$	5,062
Long-term debt to financing trust		206		174		206		167

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of September 30, 2010 and December 31, 2009 were as follows:


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,222	$	2,512	$	2,221	$	2,346
Long-term debt to PETT due within one year		—		—		415		426
Long-term debt to financing trusts		184		181		184		158
Preferred securities		87		72		87		63

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Recurring Fair Value Measurements

To increase consistency and comparability in fair value measurements, the FASB established 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 priced at NAV per fund share 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon

The following tables present 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 September 30, 2010 and December 31, 2009:


As of September 30, 2010	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	2,620		$	—		$	—		$	2,620
Nuclear decommissioning trust fund investments
Cash equivalents		1			63			—			64
Equity securities(b)		1,355			—			—			1,355
Commingled funds(c)		—			2,065			—			2,065
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		589			106			—			695
Debt securities issued by states of the United States and political subdivisions of the states		—			398			3			401
Corporate debt securities		—			636			—			636
Federal agency mortgage-backed securities		—			814			—			814
Commercial mortgage-backed securities (non-agency)		—			110			—			110
Residential mortgage-backed securities (non-agency)		—			8			7			15
Other debt obligations		—			52			—			52

Nuclear decommissioning trust fund investments subtotal(d)		1,945			4,252			10			6,207

Pledged assets for Zion Station decommissioning
Cash equivalents		—			9			—			9
Equity securities(b)		259			—			—			259
Commingled funds(c)		—			147			—			147
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		62			16			—			78
Debt securities issued by states of the United States and political subdivisions of the states		—			41			—			41
Corporate debt securities		—			103			—			103
Federal agency mortgage-backed securities		—			101			—			101
Commercial mortgage-backed securities (non-agency)		—			23			—			23
Residential mortgage-backed securities (non-agency)		—			2			2			4
Other debt obligations		—			14			—			14

Pledged assets for Zion Station decommissioning subtotal(e)		321			456			2			779

Rabbi trust investments
Cash equivalents		1			—			—			1
Mutual funds(f)		35			—			—			35

Rabbi trust investments subtotal		36			—			—			36

Mark-to-market derivative assets
Cash flow hedges		—			1,258			17			1,275
Other derivatives		3			2,314			104			2,421
Proprietary trading		—			361			56			417
Effect of netting and allocation of collateral(g)		(6	)		(2,869	)		(45	)		(2,920	)

Mark-to-market assets(h)		(3	)		1,064			132			1,193

Total assets		4,919			5,772			144			10,835

Liabilities
Mark-to-market derivative liabilities
Cash flow hedges		—			(5	)		—			(5	)
Other derivatives		(3	)		(1,188	)		(20	)		(1,211	)
Proprietary trading		—			(356	)		(28	)		(384	)
Effect of netting and allocation of collateral(g)		3			1,502			20			1,525

Mark-to-market liabilities(h)		—			(47	)		(28	)		(75	)

Deferred compensation		—			(73	)		—			(73	)

Total liabilities		—			(120	)		(28	)		(148	)

Total net assets	$	4,919		$	5,652		$	116		$	10,687

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


As of December 31, 2009	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	1,845		$	—		$	—		$	1,845
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—			122
Equity securities(b)		1,528			—			—			1,528
Commingled funds(c)		—			2,086			—			2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—			630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—			454
Corporate debt securities		—			710			—			710
Federal agency mortgage-backed securities		—			887			—			887
Commercial mortgage-backed securities (non-agency)		—			91			—			91
Residential mortgage-backed securities (non-agency)		—			9			—			9
Other debt obligations		—			76			—			76

Nuclear decommissioning trust fund investments subtotal(d)		2,041			4,552			—			6,593

Rabbi trust investments
Cash equivalents		28			—			—			28
Mutual funds(f)		13			—			—			13

Rabbi trust investments subtotal		41			—			—			41

Mark-to-market derivative net (liabilities) assets(g)(h)		(4	)		852			(44	)		804

Total assets (liabilities)		3,923			5,404			(44	)		9,283

Liabilities
Deferred compensation		—			(82	)		—			(82	)
Servicing liability		—			—			(2	)		(2	)

Total liabilities		—			(82	)		(2	)		(84	)

Total net assets	$	3,923		$	5,322		$	(46	)	$	9,199

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

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

(c)

Generation’s NDT 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 Standard and Poor’s 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 assets (liabilities) of $(60) million and $76 million at September 30, 2010 and December 31, 2009, respectively. These items consist of receivables related to pending securities sales net of cash, interest receivables and payables related to pending securities purchases.

(e)	Excludes net assets of $22 million at September 30, 2010. These items consist of receivables related to pending securities net of cash, interest receivables and payables related to pending securities purchases.

(f)	Excludes $24 million and $23 million of the cash surrender value of life insurance investments at September 30, 2010 and December 31, 2009, respectively.

(g)

Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $1,367 million and $25 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2010. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $941 million and $3 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2009.

(h)

The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $476 million and $651 million at September 30, 2010 and $302 million and $669 million at December 31, 2009, respectively, related to the fair value of Generation’s financial swap contract with ComEd; and current and noncurrent assets of $3 million and $2 million at September 30, 2010 and a noncurrent asset of $2 million at December 31, 2009, respectively, related to the fair value of Generation’s block contracts with PECO, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 nine months ended September 30, 2010 and 2009:


Three Months Ended September 30, 2010(a)	Nuclear Decommissioning Trust Fund Investments(e)			Mark-to-Market Derivatives			Total
Balance as of June 30, 2010	$	1		$	67		$	68
Total realized / unrealized gains (losses)
Included in income		—			30	(b)		30
Included in other comprehensive income		—			14	(c)		14
Change in collateral		—			(14	)		(14	)
Purchases, sales, issuances, and settlements
Purchases		12			4			16
Sales		(1	)		—			(1	)
Transfers out of Level 3 — Liability		—			3			3

Balance as of September 30, 2010	$	12		$	104		$	116

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2010	$	—		$	34		$	34


Nine Months Ended September 30, 2010(a)	Servicing Liability			Nuclear Decommissioning Trust Fund Investments(e)			Mark-to-Market Derivatives			Total
Balance as of December 31, 2009	$	(2	)	$	—		$	(44	)	$	(46	)
Total realized / unrealized gains (losses)
Included in income		2	(d)		—			110	(b)		112
Included in other comprehensive income		—			—			21	(c)		21
Included in regulatory assets		—			—			(2	)		(2	)
Change in collateral		—			—			(22	)		(22	)
Purchases, sales, issuances, and settlements
Purchases		—			13			15			28
Sales		—			(1	)		—			(1	)
Transfers out of Level 3 — Liability		—			—			26			26

Balance as of September 30, 2010	$	—		$	12		$	104		$	116

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2010	$	—		$	—		$	112		$	112

(a)	Effective December 31, 2009, Exelon categorizes its NDT commingled funds within the Level 2 fair value hierarchy.

(b)	Includes the reclassification of $4 million and $2 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2010, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)

Excludes increases in fair value of $186 million and $386 million and realized losses reclassified from OCI due to settlements of $69 million and $230 million associated with Generation’s financial swap contract with ComEd for the three and nine months ended September 30, 2010, respectively. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in the fair value of the block contracts with PECO for the three months ended September 30, 2010, as the mark-to-market balances previously recorded will be amortized over the term of the contract. The increase in fair value was $3 million through May 31, 2010. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 6 — Debt and Credit Agreements for additional information.

(e)	Includes purchases of $2 million at September 30, 2010 related to pledged assets for Zion Station decommissioning.


Three Months Ended September 30, 2009	Servicing Liability			Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of June 30, 2009	$	(2	)	$	1,679	$	12		$	1,689
Total realized / unrealized gains (losses)
Included in income		—			78		(31	)(a)(c)		47
Included in other comprehensive income		—			—		(4	)(b)		(4	)
Included in regulatory assets		—			191		(1	)		190
Purchases, sales and issuances, net		—			3		—			3
Transfers into or (out of) Level 3		—					(14	)		(14	)

Balance as of September 30, 2009	$	(2	)	$	1,951	$	(38	)	$	1,911

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2009	$	—		$	116	$	(18	)	$	98

Nine Months Ended September 30, 2009	Servicing Liability			Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of December 31, 2008	$	(2	)	$	1,220	$	106		$	1,324
Total realized / unrealized gains (losses)
Included in income		—			119		(132	)(a)(c)		(13	)
Included in other comprehensive income		—			—		6	(b)(d)		6
Included in regulatory assets (liabilities)		—			275		(2	)		273
Purchases, sales and issuances, net		—			337		—			337
Transfers into (out of ) Level 3		—			—		(16	)		(16	)

Balance as of September 30, 2009	$	(2	)	$	1,951	$	(38	)	$	1,911

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2009	$	—		$	156	$	(89	)	$	67

(a)	Includes the reclassification of $11 million and $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2009, respectively.

(b)

Excludes increases in fair value of $140 million and $808 million and realized losses due to settlements of $93 million and $180 million associated with Generation’s financial swap contract with ComEd for the three and nine months ended September 30, 2009, respectively. All amounts eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)	Includes $2 million of changes in cash collateral received for the three and nine months ended September 30, 2009, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.

(d)	Includes $1 million of changes in cash collateral sent for the nine months ended September 30, 2009, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities

The following tables present 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 nine months ended September 30, 2010 and 2009:


	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the three months ended September 30, 2010	$	(6	)	$	26		$	10		$	—
Total gains included in income for the nine months ended September 30, 2010	$	7		$	62		$	41		$	2
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2010 for the three months ended September 30, 2010	$	(1	)	$	24		$	11		$	—
Change in the unrealized gains relating to assets and liabilities held as of September 30, 2010 for the nine months ended September 30, 2010	$	22		$	57		$	33		$	—

	Operating Revenue			Purchased Power			Fuel			Other, net(a)
Total gains (losses) included in income for the three months ended September 30, 2009	$	(23	)	$	(11	)	$	3		$	78
Total gains (losses) included in income for the nine months ended September 30, 2009	$	(65	)	$	(17	)	$	(50	)	$	119
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the three months ended September 30, 2009	$	(1	)	$	(8	)	$	(9	)	$	116
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the nine months ended September 30, 2009	$	(1	)	$	(15	)	$	(73	)	$	156

(a)

Other, net activity consists of realized and unrealized gains included in income for the NDT funds held by Generation. Pursuant to the original authoritative guidance for fair value measurements, commingled funds within the NDT funds were classified in Level 3 of the fair value hierarchy. As a result of authoritative guidance issued by the FASB in the third quarter of 2009, the commingled funds were reclassified to Level 2 as of December 31, 2009.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Generation

The following tables present 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 September 30, 2010 and December 31, 2009:


As of September 30, 2010	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	2,149		$	—		$	—		$	2,149
Nuclear decommissioning trust fund investments
Cash equivalents		1			63			—			64
Equity securities(b)		1,355			—			—			1,355
Commingled funds(c)		—			2,065			—			2,065
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		589			106			—			695
Debt securities issued by states of the United States and political subdivisions of the states		—			398			3			401
Corporate debt securities		—			636			—			636
Federal agency mortgage-backed securities		—			814			—			814
Commercial mortgage-backed securities (non-agency)		—			110			—			110
Residential mortgage-backed securities (non-agency)		—			8			7			15
Other debt obligations		—			52			—			52

Nuclear decommissioning trust fund investments subtotal(d)		1,945			4,252			10			6,207

Pledged assets for Zion Station decommissioning
Cash equivalents		—			9			—			9
Equity securities(b)		259			—			—			259
Commingled funds(c)		—			147			—			147
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		62			16			—			78
Debt securities issued by states of the United States and political subdivisions of the states		—			41			—			41
Corporate debt securities		—			103			—			103
Federal agency mortgage-backed securities		—			101			—			101
Commercial mortgage-backed securities (non-agency)		—			23			—			23
Residential mortgage-backed securities (non-agency)		—			2			2			4
Other debt obligations		—			14			—			14

Pledged assets for Zion Station decommissioning subtotal(e)		321			456			2			779

Rabbi trust investments(f)(g)		4			—			—			4
Mark-to-market derivative assets
Cash flow hedges		—			1,258			1,149			2,407
Other derivatives		3			2,297			104			2,404
Proprietary trading		—			361			56			417
Effect of netting and allocation of collateral(h)		(6	)		(2,869	)		(45	)		(2,920	)

Mark-to-market (liabilities) assets(i)		(3	)		1,047			1,264			2,308

Total assets		4,416			5,755			1,276			11,447

Liabilities
Mark-to-market derivative liabilities
Cash flow hedges		—			(5	)		—			(5	)
Other derivatives		(3	)		(1,188	)		(16	)		(1,207	)
Proprietary trading		—			(356	)		(28	)		(384	)
Effect of netting and allocation of collateral(h)		3			1,502			20			1,525

Mark-to-market liabilities		—			(47	)		(24	)		(71	)

Deferred compensation		—			(20	)		—			(20	)

Total liabilities		—			(67	)		(24	)		(91	)

Total net assets	$	4,416		$	5,688		$	1,252		$	11,356

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


As of December 31, 2009	Level 1			Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	1,040		$	—		$	—	$	1,040
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—		122
Equity securities(b)		1,528			—			—		1,528
Commingled funds(c)		—			2,086			—		2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—		630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—		454
Corporate debt securities		—			710			—		710
Federal agency mortgage-backed securities		—			887			—		887
Commercial mortgage-backed securities (non-agency)		—			91			—		91
Residential mortgage-backed securities (non-agency)		—			9			—		9
Other debt obligations		—			76			—		76

Nuclear decommissioning trust fund investments subtotal(d)		2,041			4,552			—		6,593

Rabbi trust investments(f)(g)		4			—			—		4
Mark-to-market derivative net (liabilities) assets(h)(i)		(4	)		842			931		1,769

Total assets		3,081			5,394			931		9,406

Liabilities
Deferred compensation		—			(23	)		—		(23	)

Total liabilities		—			(23	)		—		(23	)

Total net assets	$	3,081		$	5,371		$	931	$	9,383

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

(b)	Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the Standard and Poor’s 500 Index, Russell 3000 Index or Morgan Stanley Capital International EAFE Index.

(c)

(d)	Excludes net assets (liabilities) of $(60) million and $76 million at September 30, 2010 and December 31, 2009, respectively. These items consist of receivables related to pending securities sales net of cash, interest receivables and payables related to pending securities purchases.

(e)	Excludes net assets of $22 million at September 30, 2010. These items consist of receivables related to pending securities sales net of cash, interest receivables and payables related to pending securities purchases.

(f)	The mutual funds held by the Rabbi trusts that are invested in common stock of Standard and Poor’s 500 companies and Pennsylvania municipal bonds are primarily rated as investment grade.

(g)	Excludes $7 million of the cash surrender value of life insurance investments at September 30, 2010 and December 31, 2009.

(h)

(i)

The Level 3 balance includes current and noncurrent assets for Generation of $476 million and $651 million at September 30, 2010 and $302 million and $669 million at December 31, 2009, respectively, related to the fair value of Generation’s financial swap contract with ComEd; and current and noncurrent assets of $3 million and $2 million at September 30, 2010, respectively, and a noncurrent asset of $2 million at December 31, 2009, related to the fair value of Generation’s block contracts with PECO. All of the mark-to-market balances Generation carries associated with the financial swap contract with ComEd and the block contracts with PECO eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2010 and 2009:


Three Months Ended September 30, 2010(a)	Nuclear Decommissioning Trust Fund Investments(d)			Mark-to-Market Derivatives			Total
Balance as of June 30, 2010	$	1		$	1,086		$	1,087
Total realized / unrealized losses
Included in income		—			30	(b)		30
Included in other comprehensive income		—			131	(c)		131
Change in collateral		—			(14	)		(14	)
Purchases, sales, issuances, and settlements
Purchases		12			4			16
Sales		(1	)		—			(1	)
Transfers out of Level 3 — Liability		—			3			3

Balance as of September 30, 2010	$	12		$	1,240		$	1,252

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held as of September 30, 2010	$	—		$	34		$	34


Nine Months Ended September 30, 2010(a)	Nuclear Decommissioning Trust Fund Investments(d)			Mark-to-Market Derivatives			Total
Balance as of December 31, 2009	$	—		$	931		$	931
Total realized / unrealized gains
Included in income		—			110	(b)		110
Included in other comprehensive income		—			180	(c)		180
Change in collateral		—			(22	)		(22	)
Purchases, sales, issuances, and settlements
Purchases		13			15			28
Sales		(1	)		—			(1	)
Transfers out of Level 3 — Liability		—			26			26

Balance as of September 30, 2010	$	12		$	1,240		$	1,252

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held as of September 30, 2010	$	—		$	112		$	112

(a)	Effective December 31, 2009, Exelon categorizes its NDT commingled funds within the Level 2 fair value hierarchy.

(b)	Includes the reclassification of $4 million and $2 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2010, respectively.

(c)

Includes increases in fair value of $186 million and $386 million and realized losses reclassified from OCI due to settlements of $69 million and $230 million associated with Generation’s financial swap contract with ComEd for the three and nine months ended September 30, 2010, respectively. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in fair value of the block contracts with PECO for the three months ended September 30, 2010, as the mark-to-market balances previously recorded will be amortized over the term of the contract. The increase in fair value was $3 million through May 31, 2010. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	Includes purchases of $2 million at September 30, 2010 related to pledged assets for Zion Station decommissioning.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Three Months Ended September 30, 2009	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of June 30, 2009	$	1,679	$	1,051		$	2,730
Total realized / unrealized gains (losses)
Included in income		78		(31	)(a)(c)		47
Included in other comprehensive income		—		43			43
Included in noncurrent payables to affiliates		191		—			191
Purchases, sales, issuances and settlements, net		3		—			3
Transfers into or (out of) Level 3		—		(14	)		(14	)

Balance as of September 30, 2009	$	1,951	$	1,049		$	3,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2009	$	116	$	(18	)	$	98


Nine Months Ended September 30, 2009	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of December 31, 2008	$	1,220	$	562		$	1,782
Total realized / unrealized gains (losses)
Included in income		119		(132	)(a)(c)		(13	)
Included in other comprehensive income		—		635	(b)(d)		635
Included in noncurrent payables to affiliates		275		—			275
Purchases, sales, issuances and settlements, net		337		—			337
Transfers out of Level 3		—		(16	)		(16	)

Balance as of September 30, 2009	$	1,951	$	1,049		$	3,000

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of September 30, 2009	$	156	$	(89	)	$	67

(a)	Includes the reclassification of $11 million and $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2009, respectively.

(b)

Includes increases in fair value of $140 million and $808 million and realized losses due to settlements of $93 million and $180 million associated with Generation’s financial swap contract with ComEd for the three and nine months ended September 30, 2009, respectively. Includes $1 million of changes in the fair value of Generation’s block contracts with PECO for the nine months ended September 30, 2009. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	Includes $2 million of changes in cash collateral received for the three and nine months ended September 30, 2009, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.

(d)	Includes $1 million of changes in cash collateral sent, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the three months ended September 30, 2010	$	(6	)	$	26		$	10		$	—
Total gains included in income for the nine months ended September 30, 2010	$	7		$	62		$	41		$	—
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2010 for the three months ended September 30, 2010	$	(1	)	$	24		$	11		$	—
Change in the unrealized gains relating to assets and liabilities held as of September 30, 2010 for the nine months ended September 30, 2010	$	22		$	57		$	33		$	—

	Operating Revenue			Purchased Power			Fuel			Other, net(a)
Total gains (losses) included in income for the three months ended September 30, 2009	$	(23	)	$	(11	)	$	3		$	78
Total gains (losses) included in income for the nine months ended September 30, 2009	$	(65	)	$	(17	)	$	(50	)	$	119
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the three months ended September 30, 2009	$	(1	)	$	(8	)	$	(9	)	$	116
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the nine months ended September 30, 2009	$	(1	)	$	(15	)	$	(73	)	$	156

(a)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

ComEd

The following tables present assets and liabilities 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 September 30, 2010 and December 31, 2009:


As of September 30, 2010	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	1	$	—		$	—		$	1
Rabbi trust investments
Cash equivalents		1		—			—			1
Mutual funds		22		—			—			22

Rabbi trust investment subtotal		23		—			—			23

Total assets		24		—			—			24

Liabilities
Deferred compensation obligation		—		(7	)		—			(7	)
Mark-to-market derivative liabilities(b)		—		—			(1,127	)		(1,127	)

Total liabilities		—		(7	)		(1,127	)		(1,134	)

Total net assets (liabilities)	$	24	$	(7	)	$	(1,127	)	$	(1,110	)


As of December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	25	$	—		$	—		$	25
Rabbi trust investments
Cash equivalents		28		—			—			28

Total assets		53		—			—			53

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities(b)		—		—			(971	)		(971	)

Total liabilities		—		(8	)		(971	)		(979	)

Total net assets (liabilities)	$	53	$	(8	)	$	(971	)	$	(926	)

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

(b)

The Level 3 balance is comprised of the current and noncurrent liability of $476 million and $651 million at September 30, 2010, respectively, and $302 million and $669 million at December 31, 2009, respectively, related to the fair value of ComEd’s financial swap contract with Generation, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Three Months Ended September 30, 2010	Mark-to-Market Derivatives
Balance as of June 30, 2010	$	(1,010	)
Total realized / unrealized losses included in regulatory assets(a)		(117	)

Balance as of September 30, 2010	$	(1,127	)


Nine Months Ended September 30, 2010	Mark-to-Market Derivatives
Balance as of December 31, 2009	$	(971	)
Total realized / unrealized losses included in regulatory assets(a)		(156	)

Balance as of September 30, 2010	$	(1,127	)

(a)

Includes decreases in fair value of $186 million and $386 million and realized gains due to settlements of $69 million and $230 million associated with ComEd’s financial swap contract with Generation for the three and nine months ended September 30, 2010, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended September 30, 2009	Mark-to-Market Derivatives
Balance as of June 30, 2009	$	(1,037	)
Total realized / unrealized losses included in regulatory assets(a)		(47	)

Balance as of September 30, 2009	$	(1,084	)


Nine Months Ended September 30, 2009	Mark-to-Market Derivatives
Balance as of December 31, 2008	$	(456	)
Total realized / unrealized losses included in regulatory assets(a)		(628	)

Balance as of September 30, 2009	$	(1,084	)

(a)

Includes decreases in fair value of $140 million and $808 million and realized gains due to settlements of $93 million and $180 million associated with ComEd’s financial swap contract with Generation for the three and nine months ended September 30, 2009, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

PECO

The following tables present 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 September 30, 2010 and December 31, 2009:


As of September 30, 2010	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	409	$	—		$	—		$	409
Rabbi trust investments — mutual funds(b)(c)		7		—			—			7

Total assets		416		—			—			416

Liabilities
Deferred compensation obligation		—		(22	)		—			(22	)
Mark-to-market derivative liabilities(d)		—		—			(9	)		(9	)

Total liabilities		—		(22	)		(9	)		(31	)

Total net assets (liabilities)	$	416	$	(22	)	$	(9	)	$	385


As of December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	281	$	—		$	—		$	281
Rabbi trust investments — mutual funds(b)(c)		7		—			—			7

Total assets		288		—			—			288

Liabilities
Deferred compensation obligation		—		(25	)		—			(25	)
Mark-to-market derivative liabilities(d)		—		—			(4	)		(4	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(25	)		(6	)		(31	)

Total net assets (liabilities)	$	288	$	(25	)	$	(6	)	$	257

(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 common stock of Standard and Poor’s 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)	Excludes $13 million and $12 million of the cash surrender value of life insurance investments at September 30, 2010 and December 31, 2009.

(d)

The Level 3 balance is comprised of the current and noncurrent liability of $6 million and $3 million at September 30, 2010, respectively, and the noncurrent liability of $4 million at December 31, 2009, related to the fair value of PECO’s block contracts. These liability balances include a $3 million and $2 million current and noncurrent liability, respectively, at September 30, 2010, and a noncurrent liability of $2 million at December 31, 2009, related to the fair value of PECO’s block contracts with Generation that eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

There was no change in the fair value for mark-to-market derivatives during the three months ended September 30, 2010.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the nine months ended September 30, 2010 and 2009:


Nine Months Ended September 30, 2010	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2009	$	(4	)	$	(2	)	$	(6	)
Total realized / unrealized gains (losses)
Included in net income		—			2	(a)		2
Included in regulatory assets		(5	)(b)		—			(5	)

Balance as of September 30, 2010	$	(9	)	$	—		$	(9	)

(a)	The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 6 — Debt and Credit Agreements for additional information.

(b)	Includes a decrease in fair value of $3 million associated with PECO’s block contract with Generation for the nine months ended September 30, 2010 which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended September 30, 2009	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of June 30, 2009	$	(2	)	$	(2	)	$	(4	)
Total unrealized losses included in regulatory assets		(1	)		—			(1	)

Balance as of September 30, 2009	$	(3	)	$	(2	)	$	(5	)


Nine Months Ended September 30, 2009	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2008	$	—		$	(2	)	$	(2	)
Total unrealized losses included in regulatory assets		(3	)		—			(3	)

Balance as of September 30, 2009	$	(3	)	$	(2	)	$	(5	)

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 tables 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 and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations as required by the NRC. The NDT 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. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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. 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.

For fixed income securities, multiple prices from pricing services are obtained from pricing vendors whenever possible, which enables cross-provider validations 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. 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 or similar securities, adjusted for observable differences and are categorized in Level 2.

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. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month; however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. Effective December 31, 2009, commingled funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 11 — Nuclear Decommissioning for further discussion on the NDT 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.

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 is valued using the Black model, an industry standard option valuation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. 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 by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. Transfers in and out of levels are recognized as of the beginning of the month the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 generally do not occur. Transfers in and out of Level 2 and Level 3 generally occur when the contract tenure becomes more observable.

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. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. 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 7 — 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 transferred an undivided interest, adjusted daily, in customer accounts receivables designated under the agreement in exchange for proceeds of $225 million, which PECO accounted for as a sale under previous guidance on accounting for transfers of financial assets. A servicing liability was recorded for the agreement in accordance with the applicable authoritative guidance for servicing of financial assets. The servicing liability was included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the liability was determined using internal estimates based on provisions in the agreement, which were categorized

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

as Level 3 inputs in the fair value hierarchy. The servicing liability was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 6 — Debt and Credit Agreements for additional information.

6. 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 the issuance of commercial paper and borrowings under its credit facility.

As of September 30, 2010, Exelon Corporate, Generation and PECO had access to unsecured revolving credit facilities with aggregate bank commitments of $957 million, $4.8 billion and $574 million, respectively. On March 25, 2010, ComEd replaced its $952 million credit facility with a new $1 billion unsecured revolving credit facility that extends to March 25, 2013. Borrowings under ComEd’s credit facility bear interest at a rate that floats daily based upon a prime rate or at a rate fixed for a specified interest period based upon a LIBOR-based rate. Adders of up to 137.5 basis points for prime-based borrowings and 237.5 basis points for LIBOR-based borrowings are added based upon ComEd’s credit rating. As of September 30, 2010, ComEd did not have any borrowings under its credit facility.

Generation, ComEd and PECO had $7 million, $30 million and $30 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories, which expired on October 22, 2010. These facilities are solely utilized to issue letters of credit. As of September 30, 2010, letters of credit issued under these agreements totaled $5 million, $26 million and $20 million for Generation, ComEd and PECO, respectively.

On October 22, 2010, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new credit facility agreements in the amounts of $30 million, $32 million and $32 million, respectively.

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at September 30, 2010 and December 31, 2009:


Commercial paper borrowings	September 30, 2010		December 31, 2009
Exelon Corporate	$	—	$	—
Generation		—		—
ComEd		65		—
PECO		—		—

Credit facility borrowings
ComEd	$	—	$	155

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Issuance of Long-Term Debt

During the nine months ended September 30, 2010, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount(a)

Use of Proceeds

Generation

Senior Notes(b)

4.00

October 1, 2020

550

To be used to finance the anticipated acquisition of JDR and for general corporate purposes.(c)

Generation

Senior Notes(b)

5.75

October 1, 2041

350

To be used to finance the anticipated acquisition of JDR and for general corporate purposes.

ComEd

First Mortgage
Bonds(b)

4.00

August 1, 2020

500

Used to refinance First Mortgage Bonds, Series 102, which matured on August 15, 2010 and for other general corporate purposes.

(a)	Excludes unamortized bond discounts of $1 million on Generation’s senior notes due 2020 and 2041, respectively.

(b)	In connection with these debt issuances, Generation and ComEd entered into treasury rate locks in the aggregate notional amounts of $600 million and $350 million, respectively. See Note 7 — Derivative Financial Instruments for additional information on Generation’s and ComEd’s treasury rate locks.

(c)

Under the terms of the debt agreement governing the senior notes due 2020, Generation will be required to repurchase those notes prior to their stated maturity if the agreement to purchase JDR is terminated or if the transaction is not completed by March 31, 2011. As a result, Generation has classified amounts outstanding under this debt agreement as long-term debt due within one year. If the acquisition is consummated by March 31, 2011, the debt will be classified to long-term debt. See Note 4 — Acquisitions for additional information on the acquisition of JDR.

During the nine months ended September 30, 2009, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount(a)

Use of Proceeds

Generation

Pollution Control
Notes

5.00

December 1, 2042

Used to refinance unenhanced tax-exempt variable rate debt that was repurchased on February 23, 2009.

Generation

Senior Notes

5.20

6.25

October 1, 2019

October 1, 2039

600

900

Used to finance the purchase and optional redemption of Generation’s Senior Notes due June 15, 2011 and for general corporate purposes, including distributions to Exelon and in contemplation of Generation’s September 2009 repurchase of variable-rate long-term tax-exempt debt. The distributions were used to finance the purchase and optional redemption of Exelon’s Senior Notes due May 1, 2011.

ComEd

First Mortgage
Bonds(b)

Variable

March 1, 2020

Used to repay credit facility borrowings incurred to repurchase bonds.

ComEd

First Mortgage
Bonds(b)

Variable

March 1, 2021

Used to repay credit facility borrowings incurred to repurchase bonds.

ComEd

First Mortgage
Bonds(b)

Variable

March 1, 2017

Used to repay credit facility borrowings incurred to repurchase bonds.

PECO

First Mortgage
Bonds

5.00

October 1, 2014

250

Used to refinance short-term debt and for other general corporate purposes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(a)	Excludes unamortized bond discounts of $1 million on Generation’s senior notes due 2019 and 2039, respectively.

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

Retirement of Long-Term Debt

During the nine months ended September 30, 2010, the following long-term debt was retired::

Company

Type

Interest Rate

Maturity

Amount

Exelon

2005 Senior Notes

4.45

June 15, 2010

400

Generation

Kennett Square Capital Lease

7.83

September 20, 2020

Generation

Montgomery County Series 1994 B Tax Exempt Bonds

Variable

June 1, 2029

Generation

Indiana County Series 2003 A Tax Exempt Bonds

Variable

June 1, 2027

Generation

York County Series 1993 A Tax Exempt Bonds

Variable

August 1, 2016

Generation

Salem County 1993 Series A Tax Exempt Bonds

Variable

March 1, 2025

Generation

Delaware County Series 1993 A Tax Exempt Bonds

Variable

August 1, 2016

Generation

Montgomery County Series 1996 A Tax Exempt Bonds

Variable

March 1, 2034

Generation

Montgomery County Series 1994 A Tax Exempt Bonds

Variable

June 1, 2029

ComEd

Sinking fund debentures

4.75

December 1, 2011

ComEd

First Mortgage Bonds

4.74

August 15, 2010

212

PECO

PETT Transition Bonds

6.52

September 1, 2010

806

During the nine months ended September 30, 2009, the following long-term debt was retired:

Company

Type

Interest Rate

Maturity

Amount

Exelon

Senior Notes

6.75

May 1, 2011

387

Generation

Kennett Square Capital Lease

7.83

September 20, 2020

Generation

Notes Payable

6.33

August 8, 2009

Generation

Pollution Control Notes

Variable

October 1, 2034

Generation

Pollution Control Notes

Variable

December 1, 2029

Generation

Pollution Control Notes

Variable

December 1, 2042

Generation

Pollution Control Notes

Variable

April 1, 2021

Generation

Pollution Control Notes

Variable

October 1, 2030

161

Generation

Senior Notes

6.95

June 15, 2011

555

ComEd

Sinking fund debentures

4.625-4.75

Various

ComEd

First Mortgage Bonds

5.70

January 15, 2009

ComEd

First Mortgage Bonds(a)

Variable

March 1, 2020

ComEd

First Mortgage Bonds(a)

Variable

March 1, 2021

ComEd

First Mortgage Bonds(a)

Variable

March 1, 2017

PECO

PETT Transition Bonds

6.52

March 1, 2010

214

PECO

PETT Transition Bonds

7.65

September 1, 2009

319

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Variable Rate Debt

Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as Long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under existing long-term credit facilities.

Generation had letter of credit facilities that expired during the second quarter of 2010, which were used to enhance the credit of variable-rate long-term tax-exempt bonds totaling $212 million, with maturities ranging from 2016 – 2034. Generation repurchased the $212 million of tax-exempt bonds during June 2010. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous.

Accounts Receivable Agreement

PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its customer accounts receivable designated under the agreement in exchange for proceeds of $225 million, which Exelon and PECO accounted for as a sale under previous guidance on accounting for transfers of financial assets. The accounting guidance was amended, effective for the Registrants on January 1, 2010, and required that this transaction be accounted for as a secured borrowing, as the transferred interest did not meet the criteria of a participating interest as defined under the authoritative guidance. Therefore, on January 1, 2010, the proceeds of $225 million representing the transferred interest in customer accounts receivable previously recorded as a contra-receivable was reclassified to a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. Additionally, the servicing liability of $2 million recorded under the previous guidance was released. As of September 30, 2010, the financial institution’s undivided interest in Exelon’s and PECO’s gross customer accounts receivable was $393 million, which is calculated under the terms of the agreement. Upon termination or liquidation of this agreement, the financial institution will be entitled to recover up to $225 million plus the accrued yield payable from the pool of receivables pledged. On September 7, 2010, PECO extended this agreement, which terminates on September 6, 2011 unless extended in accordance with its terms. As of September 30, 2010, 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 could seek alternative financing.

7. 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 exposed to market fluctuations in the prices of electricity, fossil fuels 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.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

normal purchases and normal sales scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. 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 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 2009 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading 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, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. 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 conditions, 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.

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 three-year periods. As of September 30, 2010, the percentage of expected generation hedged was 97%-100%, 87%-90%, and 62%-65% for the remainder of 2010, 2011 and 2012, 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 through the five-year financial swap contract with Generation 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 2 of the 2009 Form 10-K, qualify for the normal purchases and normal sales scope exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk related to power procurement is limited.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which along with ComEd’s remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volumes are 3,000 MW from October 2010 through May 2013. The terms of the financial swap contract require Generation to pay the around-the-clock 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. ComEd 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 2 of the 2009 Form 10-K for additional information regarding the Illinois Settlement Legislation. 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 electric supply to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under current derivative authoritative guidance. As part of the preparation for the expiration of the PPA, PECO has entered into contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk following the expiration of the electric generation rate caps through full requirements contracts and block contracts. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded will remain unchanged on PECO’s Consolidated Balance Sheet and will be amortized over the terms of the contracts.

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 delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and management agreements that are derivatives qualify for the normal purchases and normal sales exception. Additionally, in accordance with the 2009 and 2010 PAPUC 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 2009 and 2010 PGC settlements, 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 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas 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 RMC. The proprietary trading

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

activities, which included volumes of 1,077 GWhs and 2,885 GWhs for the three and nine months ended September 30, 2010 and 1,645 GWhs and 5,979 GWhs for the three and nine months ended September 30, 2009, 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 each of Exelon, Generation, and ComEd’s pre-tax income for the three and nine months ended September 30, 2010.

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. Exelon includes 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:


Income Statement Classification	Gain (Loss) on Swaps					Gain (Loss) on Borrowings
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
Interest expense	$	7	$	(5	)	$	(7	)	$	5

At September 30, 2010 and December 31, 2009, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $17 million and $10 million, respectively. During the three and nine months ended September 30, 2010 and 2009, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Cash Flow Hedges. On September 30, 2010 Generation issued and sold $350 million of senior notes due October 1, 2041. In connection with this debt issuance, Generation entered into treasury rate locks in the aggregate notional amount of $240 million. The treasury rate locks were settled on September 27, 2010. Treasury rate locks are derivative instruments used to lock in the interest rate prior to the issuance of debt. As a result of a decrease in interest rates during the period between the inception and settlement of the treasury rate locks, Generation recorded a pre-tax loss of approximately $4 million. The loss was recorded to other comprehensive income within Generation’s Consolidated Balance Sheets and will be amortized as an increase to interest expense over the life of the related debt as interest payments are made on the debt.

In connection with its August 2, 2010 issuance of First Mortgage Bonds, ComEd entered into treasury rate locks in the aggregate notional amount of $350 million. The treasury rate locks were settled on July 27, 2010. The contracts qualify and are designated for cash flow hedge accounting treatment. As interest rates decreased since the inception of the treasury rate locks, ComEd recorded a pre-tax loss of approximately $4 million. Under the authoritative accounting guidance for regulated operations, the loss was recorded as a regulatory asset within ComEd’s Consolidated Balance Sheets at settlement and will be amortized as an increase to interest expense over the life of the related debt as interest payments are made on the debt.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Other Derivatives. On September 30, 2010 Generation issued and sold $550 million of 10-year Senior Notes. In connection with this debt issuance, Generation entered into treasury rate locks in the aggregate notional amount of approximately $360 million. Treasury rate locks are derivative instruments used to lock in the interest rate prior to the issuance of debt. As a result of a decrease in interest rates during the period between the inception and settlement of the treasury rate locks, Generation recorded a pre-tax loss of approximately $5 million. The debt associated with these treasury rate locks, which will be used to fund a portion of the JDR acquisition, is subject to a mandatory redemption provision in the event the acquisition is not consummated on or prior to March 31, 2011. As a result, these treasury rate locks do not qualify for cash flow hedge accounting treatment and the associated loss was recorded to interest expense within Generation’s Consolidated Income Statements. See Note 6 — Debt and Credit Agreements for additional information on the redemption provision of this debt issuance.

Fair Value Measurement (Exelon, Generation, ComEd and PECO)

Fair value accounting guidance requires the fair value of derivative instruments 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 Consolidated Balance Sheet. 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 qualify for the normal purchases and normal sales exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2010:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges (a,d)			Other Derivatives			Proprietary Trading			Collateral and Netting (b)			Subtotal (c)			IL Settlement Swap (a)			Other Derivatives (d)			Other Derivatives		Intercompany Eliminations (a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	761		$	1,423		$	267		$	(1,929	)	$	522		$	—		$	—		$	—	$	—		$	522
Mark-to-market derivative assets with affiliate (current assets)		479			—			—			—			479			—			—			—		(479	)		—
Mark-to-market derivative assets (noncurrent assets)		514			981			150			(991	)		654			—			—			17		—			671
Mark-to-market derivative assets with affiliate (noncurrent assets)		653			—			—			—			653			—			—			—		(653	)		—

Total mark-to-market derivative assets	$	2,407		$	2,404		$	417		$	(2,920	)	$	2,308		$	—		$	—		$	17	$	(1,132	)	$	1,193

Mark-to-market derivative liabilities (current liabilities)	$	(2	)	$	(854	)	$	(241	)	$	1,033		$	(64	)	$	—		$	(3	)	$	—	$	—		$	(67	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(476	)		(3	)		—		479			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(3	)		(353	)		(143	)		492			(7	)		—			(1	)		—		—			(8	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(651	)		(2	)		—		653			—

Total mark-to-market derivative liabilities		(5	)		(1,207	)		(384	)		1,525			(71	)		(1,127	)		(9	)		—		1,132			(75	)

Total mark-to-market derivative net assets (liabilities)	$	2,402		$	1,197		$	33		$	(1,395	)	$	2,237		$	(1,127	)	$	(9	)	$	17	$	—		$	1,118

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $476 million and $651 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $862 million and $500 million, respectively, and current liabilities are shown inclusive of collateral of $33 million, respectively. The allocation of collateral had no impact on noncurrent liabilities. The total cash collateral received and offset against mark-to-market assets and liabilities was $1,395 million at September 30, 2010.

(d)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for PECO of $3 million and $2 million, respectively, related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2009:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges (a)			Other Derivatives			Proprietary Trading			Collateral and Netting (b)			Subtotal (c)			IL Settlement Swap (a)			Other Derivatives (d)			Other Derivatives		Intercompany Eliminations (a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	576		$	913		$	193		$	(1,306	)	$	376		$	—		$	—		$	—	$	—		$	376
Mark-to-market derivative assets with affiliate (current assets)		302			—			—			—			302			—			—			—		(302	)		—
Mark-to-market derivative assets (noncurrent assets)		423			792			102			(678	)		639			—			—			10		—			649
Mark-to-market derivative assets with affiliate (noncurrent assets)		671			—			—			—			671			—			—			—		(671	)		—

Total mark-to-market derivative assets	$	1,972		$	1,705		$	295		$	(1,984	)	$	1,988		$	—		$	—		$	10	$	(973	)	$	1,025

Mark-to-market derivative liabilities (current liabilities)	$	(18	)	$	(743	)	$	(172	)	$	735		$	(198	)	$	—		$	—		$	—	$	—		$	(198	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(302	)		—			—		302			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(42	)		(183	)		(98	)		302			(21	)		—			(2	)		—		—			(23	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(669	)		(2	)		—		671			—

Total mark-to-market derivative liabilities		(60	)		(926	)		(270	)		1,037			(219	)		(971	)		(4	)		—		973			(221	)

Total mark-to-market derivative net assets (liabilities)	$	1,912		$	779		$	25		$	(947	)	$	1,769		$	(971	)	$	(4	)	$	10	$	—		$	804

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $502 million and $376 million, respectively, and current liabilities are shown inclusive of collateral of $69 million, respectively. The allocation of collateral had no impact on noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $947 million at December 31, 2009.

(d)	Includes a noncurrent liability for PECO and a noncurrent asset for Generation of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2009.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Cash Flow Hedges (Exelon, Generation and ComEd). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At September 30, 2010, Generation had net unrealized pre-tax gains on effective cash flow hedges of $2,399 million being deferred within accumulated OCI, including approximately $1,127 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 September 30, 2010, approximately $1,238 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 $476 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 2010 through 2012, and the ComEd financial swap contract during 2010 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 when it is no longer probable that the forecasted transaction will occur. For the three and nine months ended September 30, 2010, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and nine months ended September 30, 2010 and 2009, 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 September 30, 2010	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 June 30, 2010			$	1,158	(a)	$	525
Effective portion of changes in fair value				401	(b)		283	(e)
Reclassifications from accumulated OCI to net income		Operating Revenue		(104	)(c)		(59	)(f)
Ineffective portion recognized in income		Purchased Power		(2	)		(2	)

Accumulated OCI derivative gain at September 30, 2010			$	1,453	(a)(d)	$	747

(a)	Includes $681 million and $610 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2010 and June 30, 2010.

(b)

Includes a $113 million gain, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended September 30, 2010. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in fair value of the block contracts with PECO for the three months ended September 30, 2010 as the mark-to-market balances previously recorded will be amortized over the term of the contract.

(c)	Includes a $42 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended September 30, 2010.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(d)	Excludes $2 million gains, net of taxes, related to interest rate swaps.

(e)	Includes $3 million of losses and $1 million of gains, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at Generation and ComEd, respectively.

(f)	Reflects the reclassification of $4 million to regulatory assets and $1 million to deferred income tax liabilities within Exelon’s and ComEd’s Consolidated Balance Sheets associated with settled treasury rate locks at ComEd.


Nine Months Ended September 30, 2010	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, 2009			$	1,152	(a)	$	551
Effective portion of changes in fair value				736	(b)		489	(e)
Reclassifications from accumulated OCI to net income		Operating Revenue		(433	)(c)		(291	)(f)
Ineffective portion recognized in income		Purchased Power		(2	)		(2	)

Accumulated OCI derivative gain at September 30, 2010			$	1,453	(a,d)	$	747

(a)

Includes $681 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2010 and December 31, 2009.

(b)

Includes a $235 million gain, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million gain, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the nine months ended September 30, 2010. During the second quarter of 2010 the block contracts with PECO were designated as normal sales. As such, the mark-to-market balance on Generation’s Consolidated Balance Sheet will be amortized over the term of the contract.

(c)	Includes a $139 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the nine months ended September 30, 2010.

(d)	Excludes $2 million gains, net of taxes, related to interest rate swaps.

(e)	Includes $3 million and $3 million of losses, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at Generation and ComEd, respectively.

(f)	Reflects the reclassification of $4 million to regulatory assets and $1 million to deferred income tax liabilities within Exelon’s and ComEd’s Consolidated Balance Sheets associated with settled treasury rate locks at ComEd.


Three Months Ended September 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 June 30, 2009			$	1,512	(a)	$	868
Effective portion of changes in fair value				177	(b)		96
Reclassifications from accumulated OCI to net income		Operating Revenue		(280	)(c)		(225	)
Ineffective portion recognized in income		Purchased Power		1			1

Accumulated OCI derivative gain at September 30, 2009			$	1,410	(a,d)	$	740

(a)	Includes $653 million and $624 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009 and June 30, 2009, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(b)	Includes a $85 million gain, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the three months ended September 30, 2009.

(c)	Includes a $56 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended September 30, 2009.

(d)	Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 6 — Debt and Credit Agreements for further information.


Nine Months Ended September 30, 2009	Income Statement Location		Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
			Generation			Exelon
			Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2008			$	855	(a)	$	563
Effective portion of changes in fair value				1,235	(b)		748
Reclassifications from accumulated OCI to net income		Operating Revenue		(686	)(c)		(577	)
Ineffective portion recognized in income		Purchased Power		6			6

Accumulated OCI derivative gain at September 30, 2009			$	1,410	(a,d)	$	740

(a)

Includes $653 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 September 30, 2009 and December 31, 2008, respectively, and $1 million, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009.

(b)	Includes a $487 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 nine months ended September 30, 2009.

(c)	Includes a $109 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd during the nine months ended September 30, 2009.

(d)	Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 6 — Debt and Credit Agreements for further information.

During the three and nine months ended September 30, 2010, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $171 million and $715 million pre-tax gain, respectively, and a $464 million and $1,138 million pre-tax gain for the three and nine months ended September 30, 2009, 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. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $3 million pre-tax for the three and nine months ended September 30, 2010, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. At September 30, 2010, cash flow hedge ineffectiveness resulted in an adjustment of $3 million to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses. During the three and nine months ended September 30, 2009, cash flow hedge ineffectiveness changed by $2 million and $10 million, respectively, primarily due to the change in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon’s energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $102 million and $485 million pre-tax gain for the three and nine months ended September 30, 2010, respectively, and a $371 million and $958 million pre-tax gain for the three and nine months ended September 30, 2009, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $3 million pre-tax for the three and nine months ended September 30, 2010, and $2 million and $10 million pre-tax for the three and nine months ended September 30, 2009, respectively.

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 nine months ended September 30, 2010 and 2009, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


Three Months Ended September 30, 2010	Exelon and Generation
	Purchased Power			Fuel			Total
	Purchased Power			Fuel			Total
Change in fair value	$	161		$	55		$	216
Reclassification to realized at settlement		(57	)		1			(56	)

Net mark-to-market gains	$	104		$	56		$	160

Nine Months Ended September 30, 2010	Exelon and Generation
	Exelon and Generation
	Purchased Power			Fuel			Total
	Purchased Power			Fuel			Total
Change in fair value	$	343		$	129		$	472
Reclassification to realized at settlement		(204	)		2			(202	)

Net mark-to-market gains	$	139		$	131		$	270

Three Months Ended September 30, 2009	Exelon and Generation
	Purchased Power			Fuel			Total
	Purchased Power			Fuel			Total
Change in fair value	$	81		$	(10	)	$	71
Reclassification to realized at settlement		10			47			57

Net mark-to-market gains	$	91		$	37		$	128

Nine Months Ended September 30, 2009	Exelon and Generation
	Purchased Power			Fuel			Total
	Purchased Power			Fuel			Total

Change in fair value	$	211		$	(113	)	$	98
Reclassification to realized at settlement		(72	)		122			50

Net mark-to-market gains	$	139		$	9		$	148

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30, 2010 and 2009, 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 operating 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” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Location on Income Statement		Three Months Ended September 30,						Nine Months Ended September 30,
	Location on Income Statement		2010			2009			2010			2009
Change in fair value		Operating Revenue	$	(1	)	$	(1	)	$	25		$	2
Reclassification to realized at settlement		Operating Revenue		(5	)		(21	)		(17	)		(63	)

Net mark-to-market gains (losses)		Operating Revenue	$	(6	)	$	(22	)	$	8		$	(61	)

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 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2010. 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 RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $58 million and $158 million, respectively.


Rating as of September 30, 2010	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	$	1,736	$	700	$	1,036		—	$	—
Non-investment grade		17		5		12		—		—
No external ratings
Internally rated — investment grade		60		8		52		—		—
Internally rated — non-investment grade		2		—		2		—		—

Total	$	1,815	$	713	$	1,102		—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2010
Financial institutions	$	340
Investor-owned utilities, marketers and power producers		629
Coal		5
Other		128

Total	$	1,102

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 net credit exposure. As of September 30, 2010, ComEd’s credit exposure to suppliers was immaterial.

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 2 of the 2009 Form 10-K 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 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.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that 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 September 30, 2010, PECO had no net credit exposure to energy suppliers.

PECO is permitted to recover its costs of procuring electric generation following the expiration of its electric generation rate caps on December 31, 2010 through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.

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 and asset management 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 and asset management agreements. As of September 30, 2010, PECO had credit exposure of $11 million under its natural gas supply and management agreements.

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. 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 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 in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $1,147 million and $894 million as of September 30, 2010 and December 31, 2009, respectively. As of September 30, 2010 and December 31, 2009, Generation had the contractual right of offset of $1,111 million and $778 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $36 million and $116 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have been required to provide incremental collateral of approximately $57 million or $957 million, respectively, as of September 30, 2010 and approximately $60 million or $673 million, respectively, as of December 31, 2009 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 18 of the 2009 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Beginning in 2007, under the Illinois auction rules and the SFC that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers. Generation entered into similar supplier forward contracts with other utilities, including PECO, with one-sided collateral postings only from

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above benchmark price levels, 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, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contracts, 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 September 30, 2010, ComEd did not hold any cash or letters of credit for the purpose of collateral from any of the suppliers in association with energy procurement contracts. See Note 2 of the 2009 Form 10-K for further information.

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. As of September 30, 2010, PECO did not hold any cash or letters of credit for the purpose of collateral from any of the suppliers in association with energy procurement contracts.

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 September 30, 2010, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2010, PECO could have been required to post approximately $54 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 September 30, 2010, Exelon’s interest rate swap was in an asset position, with a fair value of $17 million.

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

As of September 30, 2010 and December 31, 2009, $1 million and $6 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.

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

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2010, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2010. This valuation resulted in an increase to the pension obligations of $13 million and a decrease to other postretirement obligations of $18 million. Additionally, accumulated other comprehensive loss increased by approximately $18 million (after tax).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables present the components of Exelon’s net periodic benefit costs for the three and nine months ended September 30, 2010 and 2009. The 2010 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.50%. The 2010 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.83%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.


	Pension Benefits Three Months Ended September 30,						Other Postretirement Benefits Three Months Ended September 30,
	2010			2009			2010			2009
Service cost	$	47		$	44		$	31		$	29
Interest cost		164			163			53			52
Expected return on assets		(200	)		(194	)		(27	)		(24	)
Settlements		4			6			—			—
Amortization of:
Transition obligation		—			—			3			2
Prior service cost (benefit)		4			4			(14	)		(14	)
Actuarial loss		64			49			18			20

Net periodic benefit cost	$	83		$	72		$	64		$	65

Contractual termination benefit	$	—		$	—		$	—		$	4

	Pension Benefits Nine Months Ended September 30,						Other Postretirement Benefits Nine Months Ended September 30,
	2010			2009			2010			2009
Service cost	$	143		$	133		$	93		$	85
Interest cost		494			488			160			154
Expected return on assets		(600	)		(582	)		(81	)		(71	)
Settlements		4			6			—			—
Amortization of:
Transition obligation		—			—			7			7
Prior service cost (benefit)		11			11			(42	)		(42	)
Actuarial loss		191			147			55			64

Net periodic benefit cost	$	243		$	203		$	192		$	197

Contractual termination benefit	$	—		$	—		$	—		$	4

The following amounts were included in capital additions and operating and maintenance expense during the three and nine months ended September 30, 2010 and 2009, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and Postretirement Benefit Costs	2010		2009		2010		2009
Generation	$	68	$	61	$	202	$	180
ComEd		55		50		161		146
PECO		11		12		35		36
BSC(a)		13		18		37		42

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon expects to contribute approximately $954 million to the benefit plans in 2010, of which Generation, ComEd and PECO expect to contribute approximately $446 million, $310 million and $103 million, respectively. These amounts include an incremental $500 million contribution to Exelon’s largest pension plan made during the third quarter of 2010 not included in estimated contributions at December 31, 2009. As of September 30, 2010, Exelon had contributed $740 million of its expected 2010 total contributions, net of Medicare Part D subsidies of $7 million, of which Generation, ComEd and PECO contributed $345 million, $254 million and $68 million, net of Medicare Part D subsidies of $3 million, $2 million and $1 million, respectively.

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

In the second quarter of 2010, Exelon modified its pension investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. As a result of this modification, over time, Exelon determined that it will decrease equity investments and increase investments in fixed income securities and alternative investments in order to achieve a balanced portfolio of risk-reducing and return-seeking assets. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Over the next several years, Exelon expects to migrate to a target asset allocation of approximately 30% public equity investments, 50% fixed income investments and 20% alternative investments.

The change in the overall investment strategy would tend to lower the expected rate of return on plan assets in future years as compared to the previous strategy.

Securities Lending Programs. The majority of the benefit plans participate 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. Borrowers have the right to sell or re-pledge the loaned securities. 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 and may not be sold or re-pledged by the trustees unless the borrower defaults. 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 due to liquidity impairments resulting from current market conditions. Exelon, the trustees and the borrowers have the right to terminate the lending agreement at any time. In the event of termination, the borrowers must return the loaned securities or surrender the collateral. Losses recognized by the trust were not material during the nine months ended September 30, 2010 and 2009. Management continues to monitor the performance of the invested collateral and work closely with the trustees to limit any potential losses.

In 2008, Exelon initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral funds is approximately 11 months. The fair value of securities on loan was approximately $73 million and $356 million at September 30, 2010 and December 31, 2009, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $74 million at September 30, 2010 and $365 million

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

at December 31, 2009. 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. Exelon continues to assess its participation in securities lending programs.

Health Care Reform Legislation (Exelon, Generation, ComEd and PECO)

In March 2010, the Health Care Reform Acts were signed into law. A number of provisions in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to Medicare prescription drug benefits. Although this change does not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded charges of $24 million, $11 million and $9 million, respectively.

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 the cost of matching contributions to the savings plans for the Registrants during the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2010		2009		2010		2009
Exelon	$	20	$	18	$	61	$	53
Generation		10		9		31		27
ComEd		6		5		17		15
PECO		2		2		7		6

9. Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

The Registrants provide severance and health and welfare benefits to terminated employees primarily based upon each individual employee’s years of service and compensation level. The Registrants accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

Corporate restructuring (Exelon, Generation, ComEd and PECO). In June 2009, Exelon announced a restructured senior executive team and major spending cuts, including the elimination of approximately 500 employee positions. Exelon eliminated approximately 400 corporate support positions, mostly located at corporate headquarters, and 100 management level positions at ComEd, the majority of which was completed by

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

September 30, 2009. These actions were 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 estimated salary continuance and health and welfare severance benefits of $40 million in June 2009 as a result of the planned job reductions. Exelon recorded a net pre-tax credit of approximately $5 million and $1 million for the three months ended September 30, 2009 and December 31, 2009, respectively, due primarily to a reduction in estimated salary continuance and health and welfare severance benefits. Cash payments under the plan began in July 2009 and will continue through 2010. Substantially all cash payments are expected to be made by the end of 2010 resulting in the completion of the corporate restructuring plan.

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 nine months ended September 30, 2009:


Severance Benefits(a)(b)	Generation			ComEd		PECO			Other		Exelon
Expense (benefit) recorded — three months	$	(4	)	$	1	$	(2	)	$	—	$	(5	)
Expense recorded — nine months		11			19		3			2		35

(a)	The amounts above include $(1) million and $7 million, $(1) million and $4 million, and $(1) million and $2 million at Generation, ComEd and PECO, respectively, for amounts billed through intercompany allocations for the three and nine months ended September 30, 2009, respectively.

(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 for the three and nine months ended September 30, 2009, respectively. Severance benefits also include $4 million and $2 million at Exelon and ComEd, respectively, of contractual termination benefit expense for which the obligation is recorded in other postretirement benefits.

The following table presents the activity of severance obligations for the corporate restructuring from December 31, 2009 through September 30, 2010, excluding obligations recorded in equity:


Severance Benefits Obligation	Generation			ComEd			PECO			Other			Exelon
Balance at December 31, 2009	$	3		$	7		$	1		$	8		$	19
Cash payments		(2	)		(6	)		(1	)		(6	)		(15	)

Balance at September 30, 2010	$	1		$	1		$	—		$	2		$	4

Plant Retirements (Exelon and Generation). On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. These actions were in response to the economic outlook related to the continued operation of these four units. On February 1, 2010, Generation notified PJM that, to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date while construction of the necessary transmission upgrades were made, provided that Exelon receives the required environmental permits and adequate cost-based compensation. On March 2, 2010, PJM determined that transmission reliability upgrades will be necessary to alleviate reliability impacts. PJM has determined that reliability upgrades will be completed in a manner that will permit Generation’s retirement of the units on the following schedule: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011; Cromby Unit 2 on December 31, 2011; and Eddystone Unit 2 on June 1, 2012. These dates are dependent upon the completion of required transmission reliability upgrades and may be subject to further change. Generation revised the depreciable useful lives for these affected units to reflect the aforementioned anticipated deactivation dates. On June 10, 2010, Generation filed with FERC a reliability-must-run rate schedule providing the terms, conditions

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

and cost-based rates under which Generation will continue to operate Cromby Unit 2 and Eddystone Unit 2 for reliability purposes beyond their planned May 31, 2011 deactivation date. On September 15, 2010, the FERC issued an order finding that the reliability-must-run rate schedule was properly filed by Exelon in accordance with the deactivation provisions of the PJM Tariff, but also finding that additional information was needed to justify Generation’s cost-of-service before the rate schedule may take effect. As a result, the FERC order accepted the reliability-must-run rate schedule, but set the matter for hearing. The parties are currently engaged in settlement discussions with the assistance of a FERC settlement judge in an attempt to resolve the case without a hearing. Under the reliability-must-run rate schedule, which is subject to FERC approval, the total compensation would be approximately $8 million and $3 million of monthly fixed-cost recovery for Generation during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2, respectively. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In connection with these retirements, Exelon will eliminate approximately 280 employee positions, the majority of which are located at the units to be retired. Total expected costs for Generation related to the announced retirements is $37 million, which includes $15 million for estimated salary continuance and health and welfare severance benefits, a $17 million write down of inventory and $5 million of shut down costs. Cash payments under this plan began in January 2010 and will continue through 2013. Additionally, total expected accelerated depreciation expense is approximately $205 million.

During 2009, Generation recorded a pre-tax charge of $24 million related to the announced retirements, which included a $7 million charge for estimated salary continuance and health and welfare severance benefits, and $17 million of expense for the write down of inventory recorded within operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations. Additionally, during 2009, Generation recorded $32 million of accelerated depreciation expense within depreciation and amortization expense in Exelon’s and Generation’s Consolidated Statements of Operations. During the three months ended September 30, 2010, Generation recorded $22 million of accelerated depreciation expense. During the nine months ended September 30, 2010, Generation recorded a pre-tax credit of $2 million for a reduction in estimated salary continuance and health and welfare severance benefits and $57 million of accelerated depreciation expense.

The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from December 31, 2009 through September 30, 2010:


Severance Benefits Obligation	Exelon and Generation
Balance at December 31, 2009	$	7
Cash payments		(1	)
Other adjustments		(2	)

Balance at September 30, 2010	$	4

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:


For the Three Months Ended September 30, 2010	Exelon			Generation			ComEd			PECO
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		1.6			3.2			4.8			(5.8	)
Qualified nuclear decommissioning trust fund income		4.1			5.4			—			—
Domestic production activities deduction		(1.4	)		(1.7	)		—			—
Tax exempt income		(0.1	)		(0.1	)		—			—
Amortization of investment tax credit		(0.2	)		(0.1	)		(0.4	)		(0.4	)
Plant basis differences		—			—			(0.1	)		—
Other		0.5			—			0.2			0.6

Effective income tax rate		39.5	%		41.7	%		39.5	%		29.4	%


For the Nine Months Ended September 30, 2010	Exelon			Generation			ComEd			PECO
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		2.8			3.7			6.6			(5.9	)
Qualified nuclear decommissioning trust fund income		1.3			1.7			—			—
Domestic production activities deduction		(1.8	)		(2.4	)		—			—
Tax exempt income		(0.1	)		(0.2	)		—			—
Health care reform legislation (a)		1.7			0.9			1.7			1.7
Amortization of investment tax credit		(0.2	)		(0.2	)		(0.4	)		(0.4	)
Plant basis differences		—			—			(0.1	)		0.1
Uncertain tax position remeasurement		—			(2.6	)		11.5			—
Other		0.1			—			0.2			0.2

Effective income tax rate		38.8	%		35.9	%		54.5	%		30.7	%

(a)	See Note 8 for further discussion regarding the impact of Health Care Reform Legislation on income tax expense.


For the Three Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		4.0			4.8			22.5			(8.8	)
Qualified nuclear decommissioning trust fund income		5.6			6.2			—			—
Domestic production activities deduction		0.1			—			—			—
Tax exempt income		(0.1	)		(0.1	)		—			—
Nontaxable postretirement benefits		(0.2	)		(0.2	)		(0.3	)		(0.3	)
Amortization of investment tax credit		(0.2	)		(0.1	)		(0.5	)		(0.5	)
Plant basis differences		(0.1	)		—			(0.2	)		(0.2	)
Other		—			0.2			(1.6	)		(0.6	)

Effective income tax rate		44.1	%		45.8	%		54.9	%		24.6	%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


For the Nine Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		1.5			2.3			4.6			(6.5	)
Qualified nuclear decommissioning trust fund income		3.4			4.1			—			—
Domestic production activities deduction		(0.7	)		(0.9	)		—			—
Tax exempt income		(0.1	)		(0.2	)		—			—
Nontaxable postretirement benefits		(0.3	)		(0.2	)		(0.4	)		(0.3	)
Amortization of investment tax credit		(0.2	)		(0.1	)		(0.5	)		(0.5	)
Plant basis differences		—			—			(0.3	)		0.1
Other		—			—			(0.3	)		—

Effective income tax rate		38.6	%		40.0	%		38.1	%		27.8	%

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd and PECO have $780 million, $656 million, $73 million and $44 million, respectively, of unrecognized tax benefits as of September 30, 2010. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2009, except for those relating to the 1999 sale of fossil generating assets and competitive transition charges discussed below. See Note 10 of the 2009 Form 10-K for further discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months.

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. Responding to the Illinois Attorney General’s petition for rehearing, on July 15, 2009, the Illinois Supreme Court modified its opinion to indicate that it was to be applied only prospectively, beginning in 2009. In September 2009, the Illinois Supreme Court denied Exelon’s Petition for Rehearing.

On December 22, 2009, Exelon filed a Petition of Writ for Certiorari with the United States Supreme Court appealing the Illinois Supreme Court’s July 15, 2009 modified opinion. As a result of the filing of the United States Supreme Court petition, unrecognized tax benefits continued to be reported as of December 31, 2009. On March 1, 2010, the United States Supreme Court announced that it would not review the Illinois Supreme Court’s decision. As a result of the United States Supreme Court decision, Exelon, Generation and ComEd ceased reporting their unrecognized tax benefits as of March 31, 2010.

Tax Method of Accounting for Repairs (Exelon and Generation)

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. The new tax method of accounting resulted in net positive cash flow for the nine months ended September 30, 2010 of approximately $126 million and approximately $420 million for the year ended December 31, 2009. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. Exelon had requested and received approval from the IRS to review its methodology through its Pre-Filing Agreement program. However, in the second quarter of 2010, Exelon was informed that the IRS has suspended the pre-filing agreement process and instead intends to issue broad industry guidance with respect to electric generation power plants. If that broader guidance is issued, it is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease within the next 12 months.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Nuclear Decommissioning Liabilities (Exelon and Generation)

AmerGen 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 reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November of 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. In August 2009, the United States Department of Justice (DOJ) filed its answer denying the allegations made by Generation in its complaint. No trial date has yet been assigned, but trial could occur sometime in 2012.

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. The DOJ presently refuses to commit to participate in ADR. As a result, it is unclear whether ADR will occur and if so, when.

In addition, in the second quarter of 2010, Entergy Corporation concluded its trial in the United States Tax Court of a similar dispute involving the assumption of decommissioning liabilities in connection with the purchase of a nuclear power plant. It is possible that a decision will be reached in that case in the next twelve months. While the decision in that case would not serve as binding precedent for AmerGen’s litigation in the United States Court of Federal Claims, the reasoning of the decision may cause Generation to reevaluate the total amount of unrecognized tax benefits. Due to the possibility of quicker resolution through the ADR program and the possibility of a decision being entered in the Entergy trial, and the lesser prospect of a resolution through ADR, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

Other Income Tax Matters

IRS Appeals 1999-2001 (Exelon, ComEd and PECO)

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 IRC. Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Act. The proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain could be deferred over the lives of the replacement property under the involuntary conversion provisions. The remaining 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 IRC. 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 asserted that ComEd was not forced to sell the fossil generating plants and the sales proceeds were therefore not received in connection with an involuntary conversion of certain ComEd property

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

rights. Accordingly, the IRS 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 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 of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax.

Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon contended that the Illinois Act and the Competition 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 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. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years.

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 those customers electing to purchase electricity from providers other than ComEd. ComEd collected approximately $1.2 billion in CTCs for the years 1999-2006.

Similarly, under the Competition 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 $5.3 billion.

Status of Tax Positions. In connection with Exelon’s discussions with IRS Appeals during the second quarter of 2010, IRS Appeals proposed a settlement offer for the like-kind exchange transaction, involuntary conversion and CTC positions.

Based on the status of these settlement discussions, Exelon concluded that it had sufficient new information for the involuntary conversion and CTC positions such that a change in measurement in accordance with applicable accounting standards was required. As a result of the required re-measurement in the second quarter of 2010, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. The amount recorded at Generation reflects the reduction of current taxes payable and deferred tax liabilities for the increase in tax basis of the related assets transferred from ComEd in accordance with the Contribution Agreement dated January 1, 2001, pursuant to which ComEd’s generating business ultimately was transferred to Generation.

In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. The agreement is consistent with IRS Appeals’ second quarter offer to settle the involuntary conversion and CTC positions and also includes IRS Appeals’ agreement to withdraw its assertion of the $110 million substantial understatement penalty with respect to Exelon’s involuntary conversion position. IRS Appeals continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position. Final resolution of the involuntary

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

conversion and CTC disputes remains subject to finalizing terms and calculations and executing definitive agreements satisfactory to both parties.

Under the terms of the preliminary agreement, Exelon estimates it would make a tax and interest payment of approximately $235 million in 2011 for the years for which there is a resulting tax deficiency, of which $420 million would be paid by ComEd, $140 million would be received by PECO, $10 million would be paid by Generation and the remainder received by Exelon. These amounts are net of approximately $300 million of refunds due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM as well as other agreed upon audit adjustments. Further, Exelon expects to receive an additional tax refund of approximately $300 million between 2011 and 2014, of which $360 million would be received by ComEd, $40 million would be paid by Generation and the remainder by Exelon.

Also during the third quarter, Exelon and IRS Appeals failed to reach a settlement with respect to the like-kind exchange position and the related substantial understatement penalty. Exelon continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS in its settlement offer reflects the strength of Exelon’s position.

While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has thus far been unwilling to settle the issue without requiring a nearly complete concession of the issue by Exelon. Accordingly, to continue to contest the IRS’s disallowance of the like-kind exchange position and its assertion of the $86 million substantial understatement penalty, Exelon expects to initiate litigation in the second half of 2011 after the final resolution of the involuntary conversion and CTC settlement. Given that Exelon has determined settlement is not a realistic outcome, it has assessed in accordance with applicable 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 therefore eliminated any liability for unrecognized tax benefits during the second quarter of 2009.

As of December 31, 2009, a fully successful challenge to Exelon’s and ComEd’s like-kind exchange and involuntary conversion transactions would have accelerated income tax payments and increased interest expense related to the deferred tax gain by as much as $1.1 billion and would have negatively affected Exelon’s results of operations by as much as $300 million (after-tax) related to interest expense. As of September 30, 2010, assuming Exelon’s preliminary settlement of the involuntary conversion position is finalized and Exelon continues to contest its like-kind exchange position, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully successful IRS challenge could be as much as $810 million, of which $540 million would be paid by ComEd and the remainder by Exelon. If the IRS were to prevail in litigation on the like-kind exchange position, Exelon’s results of operations could be negatively affected due to increased interest expense, as of September 30, 2010 by as much as $220 million (after-tax), of which $170 million would be recorded at ComEd and the remainder by Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.

Based on Exelon management’s expectations as to the potential of a settlement and litigation outcome, it is reasonably possible that the unrecognized tax benefits related to these issues may significantly change within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

11. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. 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 that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.

During the third quarter of 2010, Generation’s ARO decreased by $205 million, primarily reflecting the ZionSolutions’ assumption of decommissioning and other liabilities for Zion Station (see discussion below), offset in part by accretion and by increases for updates to estimated future cash flows across all of Generation’s units. Changes in estimated future cash flows increased the ARO by $452 million, including approximately $200 million associated with the accelerated timing of the Zion Station decommissioning. The remainder of the increase is the result of cost study estimate updates and the change in timing of general decommissioning activities at select sites in Generation’s nuclear fleet, including revisions to the timing and amount of SNF disposal; partially offset by the impacts of lower escalation rates. This change in the ARO resulted in an immaterial impact to Exelon’s and Generation’s Consolidated Statements of Operations. During the third quarter of 2009, Generation recorded a net decrease in the ARO of $416 million. The ARO reduction in 2009 was primarily due to declines in expected long-term escalation rates for energy and labor costs as compared to prior study periods, partially offset by increased costs resulting from updated decommissioning cost studies received for six nuclear units. This overall decrease in the ARO in 2009 resulted in the recognition of $47 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing asset retirement cost balances for Generation’s Non-Regulatory Agreement Units.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2009 to September 30, 2010:


	Exelon and Generation
Nuclear decommissioning ARO at December 31, 2009(a)	$	3,260
Accretion expense		144
Net increase due to changes in estimated cash flows		452
Extinguishment of Zion Station ARO		(768	)
Costs incurred to decommission retired plants		(33	)

Nuclear decommissioning ARO at September 30, 2010(a)	$	3,055

(a)	Includes $5 million and $17 million as the current portion of the ARO at September 30, 2010 and December 31, 2009, respectively, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Nuclear Decommissioning Trust Fund Investments

Generation will pay for its nuclear decommissioning obligations using trust funds that have been established for this purpose. At September 30, 2010 and December 31, 2009, Exelon and Generation had NDT fund investments totaling $6,147 million and $6,669 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2010 and 2009:


	Exelon and Generation
	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a)	$	324	$	454	$	117	$	712
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)		107		153		48		204

(a)	Gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)	Gains related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.

Refer to Note 3 — Regulatory Matters for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998.

On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request that reimbursement; specifically, if certain milestones as defined within the ASA are not met, all or a portion of requested reimbursements shall be deferred until such milestones are met. The transfer of the Zion Station assets did not qualify for asset sale accounting treatment and as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd ratepayers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and maintains a liability of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

approximately $33 million which is included within the nuclear decommissioning ARO. Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of September 30, 2010, the carrying value of the Zion Station pledged assets, which include the related NDT funds; and the payable to Zion Solutions was approximately $801 million and $768 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in Other Current Liabilities within Generation’s Consolidated Balance Sheets, was $101 million.

ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.

Securities Lending Program. Generation’s NDT 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. Borrowers have the right to sell or re-pledge the loaned securities. 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. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. 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 2008, Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 18 months. The fair value of securities on loan was approximately $19 million and $357 million at September 30, 2010 and December 31, 2009, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $19 million at September 30, 2010 and $366 million at December 31, 2009. Generation continues to assess its participation in securities lending programs.

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 NDT funds is included in NDT fund earnings and classified as Other,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three and nine months ended September 30, 2010 and 2009.

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 to decommission the facility at the end of its life. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees. Generation has not received any subsequent communication from the NRC following the establishment of these additional parent guarantees. See Note 11 of the 2009 Form 10-K for further information on NRC minimum funding requirements.

Accounting Implications of the Regulatory Agreements with PECO. Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities 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 a 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 the approved Settlement permitting the NDCAC to continue after the termination of PECO’s CTC collections on December 31, 2010. The Settlement will not result in a material impact to Exelon or Generation’s future results of operations, cash flows or financial position.

See Note 11 of the 2009 Form 10-K for information regarding accounting implications of the regulatory agreement with ComEd for nuclear decommissioning.

12. 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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net income	$	845	$	757	$	2,039	$	2,126

Average common shares outstanding — basic		662		660		661		659
Assumed exercise of stock options, performance share awards and restricted stock		1		2		1		2

Average common shares outstanding — diluted		663		662		662		661

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 9 million and 8 million for the three and nine months ended September 30, 2010, respectively, and 6 million and 5 million for the three and nine months ended September 30, 2009, respectively.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2010. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

For information regarding capital commitments at December 31, 2009, see Note 18 of the 2009 Form 10-K. All significant changes in Exelon’s, Generation’s, ComEd’s and PECO’s commitments from December 31, 2009, and all significant contingencies, are disclosed below.

Energy Commitments

Generation’s, ComEd’s and PECO’s short and long-term commitments relating to the sale and purchase of energy, capacity and transmission rights as of September 30, 2010 changed from December 31, 2009 as follows:

•

Generation’s total commitments for future sales of energy to third parties decreased by approximately $213 million during the nine months ended September 30, 2010, reflecting increases of approximately $473 million, $174 million, $62 million, $18 million and $48 million related to 2011, 2012, 2013, 2014 and beyond sales commitments, respectively, offset by the fulfillment of approximately $988 million of 2010 commitments during the nine months ended September 30, 2010. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 7 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.

•

Generation’s total commitments for future net purchases of capacity from third parties decreased by $169 million during the nine months ended September 30, 2010, reflecting a decrease of approximately $1 million related to 2011 and increases of approximately $2 million, $2 million, $3 million and $54 million related to 2012, 2013, 2014 and beyond net purchase commitments, respectively, due to overall hedging activity in the normal course of business. A decrease of approximately $229 million was due to the fulfillment of 2010 commitments during the nine months ended September 30, 2010. See Note 7 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.

•

On December 17, 2009, Generation entered into a PPA with Entergy Texas, Inc. (ETI) to sell 150 MW through April 30, 2011 and 300 MW thereafter of capacity and energy from the Frontier Generating Station located in Grimes County, Texas. The approximate ten-year PPA is not included within net capacity payment commitments because it is contingent upon ETI waiving or obtaining regulatory approvals, which has not yet occurred.

•

In April 2010, the ICC approved procurement contracts that enable ComEd to meet a portion of its customers’ electricity requirements for the period from June 2010 through May 2012. These contracts resulted in an increase in ComEd’s energy commitments of $74 million for the remainder of 2010 as of September 30, 2010, $206 million for 2011 and $15 million for 2012. See Note 3 — Regulatory Matters for additional information.

•

In May 2010, ComEd entered into contracts for the procurement of RECs which resulted in an increase in ComEd’s energy commitments of $3 million for the remainder of 2010 as of September 30, 2010 and $6 million for 2011. See Note 3 — Regulatory Matters for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

•

During 2010, PECO entered into procurement contracts in order to meet a portion of its customers’ electric supply requirements for 2011 through 2015 that increased PECO’s total purchase commitments by $891 million, $357 million, $77 million, $25 million and $25 million in 2011, 2012, 2013, 2014 and 2015, respectively. See Note 3 — Regulatory Matters for additional information.

•

PECO’s AEC purchase commitments increased $21 million during the nine months ended September 30, 2010 as a result of the solar AEC purchase agreements executed in March 2010, resulting in purchases of approximately $2 million annually over 11 years. See Note 3 — Regulatory Matters for additional information.

Fuel and Natural Gas Purchase Obligations

Generation’s and PECO’s fuel purchase obligations as of September 30, 2010 changed from December 31, 2009 as follows:

•

Generation’s total fuel purchase obligations for nuclear and fossil generation have not materially changed during the nine months ended September 30, 2010.

•

PECO’s total natural gas purchase obligations increased by approximately $96 million during the nine months ended September 30, 2010, reflecting increases of $52 million and $44 million for the remainder of 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 September 30, 2010, representing commitments potentially triggered by future events changed from December 31, 2009 as follows:

•

Exelon’s letters of credit decreased $5 million due to activity at Generation, ComEd and PECO as discussed below. Guarantees increased by $143 million predominantly as a result of approximately $219 million in parent guarantees issued by Exelon as part of the remediation of the December 31, 2009 underfunded position of Generation’s Byron and Braidwood NDT funds offset by decreases in Generation’s guarantees as noted below. Guarantees decreased by $127 million for 2010, increased by $49 million for 2011, increased by $15 million for 2012, decreased by $96 million for 2013 and increased by $303 million for 2015 and beyond.

•

Generation’s letters of credit increased by $64 million and guarantees decreased by $64 million primarily as a result of energy trading activities.

•

ComEd’s letters of credit to PJM decreased by $55 million as ComEd replaced the letters of credit with $153 million of cash collateral due to more favorable carrying costs for cash.

•

ComEd’s PJM RTEP baseline project commitments decreased by $12 million for 2010 and increased by $5 million, $19 million, $53 million, $65 million and $30 million for 2011, 2012, 2013, 2014 and 2015, respectively, driven by changes in estimated timing and amount of project spending.

•

PECO’s outstanding letters of credit decreased by $19 million primarily due to letters of credit that were cancelled as a result of the completion of a tax credit purchase transaction in March 2010 and changes in the contractual collateral requirements for PECO’s medical plan.

•

PECO’s PJM RTEP baseline project commitments increased by $14 million, $14 million, $6 million and $3 million for the remainder of 2010, 2011, 2012 and 2013 driven by changes in estimated timing and amount of project spending.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Other Purchase Obligations

Exelon’s, Generation’s, ComEd’s and PECO’s other purchase obligations as of September 30, 2010, which primarily represent commitments for services, materials and information, changed from December 31, 2009 as follows:

•

Exelon’s other purchase obligations increased (decreased) by $(52) million, $65 million, $14 million, $24 million and $11 million for 2010, 2011, 2012, 2013 and 2014, respectively.

•

Generation’s other purchase obligations increased (decreased) by $(20) million, $23 million, $4 million, $7 million and $7 million for 2010, 2011, 2012, 2013 and 2014, respectively.

•

ComEd’s other purchase obligations increased (decreased) by $(1) million, $13 million, $4 million, $8 million and $3 million for 2010, 2011, 2012, 2013 and 2014, respectively.

•

PECO’s other purchase obligations increased (decreased) by $(33) million and $21 million for 2010 and 2011, respectively.

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. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at September 30, 2010.

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 guarantee 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 guarantee that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guarantee is $95 million as of September 30, 2010. The primary remaining exposures covered by this guarantee will expire in 2012.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

resulted in contamination by substances that are considered hazardous under environmental laws. ComEd and PECO have identified 42 and 27 sites, respectively, where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several PRPs which may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois EPA or U.S. EPA have approved the clean up of 11 sites and of the 27 sites identified by PECO, the PA DEP has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 25 and 9 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 2018, 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.

Pursuant to orders from the ICC and PAPUC, respectively, ComEd and PECO are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. During the third quarter of 2010, ComEd and PECO each completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $13 million and $2 million, respectively. See Note 3 — Regulatory Matters for additional information.

As of September 30, 2010 and December 31, 2009, Exelon, Generation, ComEd and PECO had accrued the following amounts for environmental liabilities:


September 30, 2010	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	183	$	160
Generation		15		—
ComEd		122		116
PECO		46		44

December 31, 2009	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	175	$	149
Generation		17		—
ComEd		113		107
PECO		45		42

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 U.S. EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act, which required 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 NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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.

In a 2007 decision, the U.S. Second Circuit Court of Appeals remanded the Phase II rule back to the U.S. EPA for revisions. 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 their locations and operations. On July 9, 2007, the U.S. EPA formally suspended the Phase II rule.

In April 2009, the U.S. Supreme Court reversed the decision of the U.S. Second Circuit Court of Appeals that had invalidated the use of a cost-benefit analysis under Section 316(b). The U.S. EPA is considering the rule on remand and will 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 U.S. EPA will issue a proposed rule on remand in first quarter of 2011. Until then, 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. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements.

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 U.S. EPA’s suspension of the Phase II rule, on January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until the draft permit is finalized. Generation believes the regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

Generation estimates that the cost to retrofit Oyster Creek with closed cycle cooling towers would be approximately $700 million to $800 million. This cost estimate is based on a study conducted in 2006 by a third party consulting firm using certain assumptions to ensure consistency with the methodology used by the U.S. EPA to estimate the capital and operating costs of compliance with the Phase II rule at Oyster Creek. This estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing incremental operating and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029. As such, should either the final Section 316(b) regulations or NJDEP requirement have performance standards that require the installation of cooling towers, Generation would close Oyster Creek prior to the time those standards would need to be met. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. If PJM requires the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or 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, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment.

Generation is contesting the requirement to install cooling towers at Oyster Creek through the administrative appeal process. It is unknown at this time whether the final regulations or permits will require closed-cycle cooling at Oyster Creek or Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Given the uncertainties associated with these proceedings and the time required for their resolution, Generation cannot predict the eventual outcome of the proceedings or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its generating facilities and its future results of operations, cash flows and financial position.

Nuclear Generating Station Groundwater. In 2005 and 2006, the Illinois EPA issued NOVs to Generation alleging violations of state groundwater standards at the Braidwood, Dresden and Byron generating stations related to tritium leaks at the plants. Tritium is 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. In addition, the Illinois Attorney General and the State’s Attorney for the counties in which the plants are located filed civil enforcement lawsuits against Generation. On March 11, 2010, Generation agreed to a settlement of all pending actions related to the leaks. Under the terms of the settlement, Generation paid approximately $1.2 million in civil penalties and funds for supplemental environmental projects in the communities where the plants are located.

Cotter Corporation. The U.S. 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 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 that required additional landfill cover. The current estimated cost of the anticipated landfill cover 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 such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the radiological contamination. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require the use of an excavation remedy is remote.

Air. On July 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. The first phase of the NO_x and SO₂ emissions reductions under the proposed Transport Rules will commence in 2012, with further reductions of SO₂ emissions proposed to become effective in 2014. These emissions limits will be further reduced as the U.S. EPA finalizes more restrictive NAAQS for ozone and fine particulate matter in the 2010–2011 timeframe.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The proposed Transport Rule regulations also would limit the use of allowance trading to achieve compliance and restrict entirely the use of pre-2012 allowances. Existing SO2 allowances under the Title IV Acid Rain Program (ARP) would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment of $57 million on its ARP SO₂ allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because proposed Transport Rule regulations would restrict entirely the use of ARP SO₂ allowances beginning in 2012. As of September 30, 2010, Generation had $16 million of emission allowances carried in inventory at the lower of weighted average cost or market.

Additionally, as of September 30, 2010, Exelon has a $622 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, the ultimate passage of the proposed Transport Rule could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.

In March 2005, the U.S. EPA finalized the CAMR, which was a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a 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 D.C. Circuit Court’s CAMR decision. The U.S. EPA is now expected to propose a new rulemaking, likely in 2011, to address HAP emissions from electric generation power plants. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal regulations are finalized by the U.S. EPA.

The U.S. EPA has announced that it will complete a review of the national ambient air quality standards by the end of 2011 for ozone (nitrogen oxide and volatile organic chemicals), particulate matter, carbon monoxide, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.

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 U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the 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 U.S. EPA requested information related to the stations in 2003, and ComEd has been cooperating with the U.S. EPA since then. The NOV states that the U.S. 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 U.S. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In August 2009, the DOJ and the Illinois Attorney General filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon were named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation’s partial motion to dismiss all but one of the claims against Midwest Generation. The Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation’s ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint substantially similar to the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd. On September 17, 2010, ComEd filed a motion requesting the Court to dismiss the governmental plaintiffs’ amended complaint. The Court has not yet ruled on that motion.

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 amended complaint, 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, while a loss may be reasonably possible, they believe the likelihood of loss is not probable. Therefore, no reserve has been established. Further, Generation believes that it would be reimbursed for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME. Exelon, Generation and ComEd cannot predict an estimated amount or range of possible loss.

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 U.S. EPA, alleging past and continuing violations of several provisions of the 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 U.S. EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the U.S. 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 U.S. 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.

On April 16, 2009, the U.S. EPA issued an NOV to ComEd and Dominion Resources Services, Inc. (Dominion) alleging past and continuing violations of several provisions of the 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, a wholly owned subsidiary of ComEd, in 1997. Both stations are currently owned and operated by Dominion. The U.S. EPA requested information related to the stations in 2009, and ComEd has been cooperating with the U.S. EPA since the time of that request. The NOV states that the U.S. 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 U.S. EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements for the Kincaid and State Line stations, 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 NOVs or any resulting enforcement action.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In connection with Exelon’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 NOVs 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 NOVs.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels.

International Climate Change Regulation. At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The next Conference of the Parties is scheduled for Mexico in the fourth quarter of 2010.

Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

Numerous bills have been introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable. It is currently unknown when Congress will resume discussion of legislation containing climate change provisions.

In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. In response to the decision, on July 11, 2008, the U.S. EPA issued an Advance Notice of Proposed Rulemaking to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act. On December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act will trigger permitting requirements under the Prevention of Significant Deterioration and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO₂ equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO₂ equivalent basis. These thresholds are effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. Under the regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis.

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

Regional and State Climate Change Legislation and Regulation. At a regional level, on November 15, 2007, 6 Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) signed the Midwestern Greenhouse Gas Accord. Under that Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In May 2010, an advisory group appointed by the Governors issued recommendations, which are now under review by the Governors.

At the state level, the PCCA was signed into law in July 2008. The PCCA requires, among other things, that a Climate Change Advisory Committee be formed, that a report on the potential impact of climate change in Pennsylvania be developed, that the PA DEP develop a GHG inventory for Pennsylvania, that a voluntary GHG registry be identified, and that the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan on October 9, 2009 and they are currently being considered by the Pennsylvania legislature.

At this time, Exelon is unable to estimate the potential impacts of any future mandatory GHG legal or regulatory requirements on its businesses.

Litigation Matters

Except to the extent noted below, the circumstances set forth in Note 18 of the 2009 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

At September 30, 2010 and December 31, 2009, Generation had reserved approximately $54 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2010, approximately $17 million of this amount related to 190 open claims presented to Generation, while the remaining $37 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 the nine months ended September 30, 2010, Generation increased its reserve by approximately $5 million, primarily due to an increase in forecasted claims. Updates to this reserve in 2009 did not result in material adjustments.

Exelon

Pension Claims. On February 22, 2010, the U.S. Supreme Court declined to hear an appeal of the July 2, 2009 decision of the U.S. Court of Appeals for the Seventh Circuit affirming dismissal of claims that the calculation of lump sum benefits earned under the Exelon Corporation Cash Balance Pension Plan (Plan) did not comply with ERISA. The Plan’s motion for summary judgment on remaining claims regarding the Plan’s calculation of lump sum benefits earned under a prior, traditional pension formula remains pending before the U.S. District Court for the Northern District of Illinois.

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.

Income Taxes

See Note 10 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

100

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009:


Three Months Ended September 30, 2010	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	288	$	121	$	119	$	43
Regulatory assets(a)		290		—		7		283
Nuclear fuel(b)		173		173		—		—
Asset retirement obligation accretion(c)		49		49		—		—

Total depreciation, amortization and accretion	$	800	$	343	$	126	$	326


Nine Months Ended September 30, 2010	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	845	$	344	$	352	$	128
Regulatory assets(a)		766		—		34		731
Nuclear fuel(b)		496		496		—		—
Asset retirement obligation accretion(c)		148		147		1		—

Total depreciation, amortization and accretion	$	2,255	$	987	$	387	$	859


Three Months Ended September 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	242	$	74	$	112	$	42
Regulatory assets(a)		243		—		13		230
Nuclear fuel(b)		143		143		—		—
Asset retirement obligation accretion(c)		54		54		—		—

Total depreciation, amortization and accretion	$	682	$	271	$	125	$	272


Nine Months Ended September 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	716	$	223	$	332	$	121
Regulatory assets(a)		644		—		39		605
Nuclear fuel(b)		415		415		—		—
Asset retirement obligation accretion(c)		160		159		1		—

Total depreciation, amortization and accretion	$	1,935	$	797	$	372	$	726

(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.

101

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Three Months Ended September 30, 2010	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)	$	41		$	41		$	—	$	—
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)		12			12			—		—
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units		324			324			—		—
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units		107			107			—		—
Regulatory offset to decommissioning trust fund-related activities(b)		(292	)		(292	)		—		—

Total decommissioning-related activities		192			192			—		—

Long-term lease income		7			—			—		—
Interest income related to uncertain income tax positions		—			—			1		—
Other		7			—			2		3

Other, net	$	206		$	192		$	3	$	3


Nine Months Ended September 30, 2010	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)	$	140		$	140		$	—	$	—
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)		38			38			—		—
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units		117			117			—		—
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units		48			48			—		—
Regulatory offset to decommissioning trust fund-related activities(b)		(206	)		(206	)		—		—

Total decommissioning-related activities		137			137			—		—

Long-term lease income		20			—			—		—
Interest income related to uncertain income tax positions		—			—			3		—
Other		21			1			11		6

Other, net	$	178		$	138		$	14	$	6

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

(b)

Includes the elimination of NDT fund related activity for the Regulatory Agreement Units, including the elimination of net realized income and income taxes related to all NDT fund activity for these units. See Note 11 of the 2009 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

102

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Three Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)	$	53		$	53		$	—		$	—
Net realized losses on decommissioning trust funds — Non-Regulatory Agreement Units(a)		(3	)		(3	)		—			—
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units		454			454			—			—
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units		153			153			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(406	)		(406	)		—			—

Total decommissioning-related activities		251			251			—			—

Long-term lease income		6			—			—			—
Interest income (expense) related to uncertain income tax positions(c)		(24	)		(4	)		(23	)		1
Losses on early retirement of debt		(93	)		(57	)		—			—
Other		8			2			4			1

Other, net	$	148		$	192		$	(19	)	$	2


Nine Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)	$	81		$	81		$	—		$	—
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)		16			16			—			—
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units		712			712			—			—
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units		204			204			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(639	)		(639	)		—			—

Total decommissioning-related activities		374			374			—			—

Investment income		1			—			—			1
Long-term lease income		19			—			—			—
Interest income related to uncertain income tax positions(c)		51			—			64			4
Other-than-temporary impairment to Rabbi trust investments(d)		(7	)		—			(7	)		—
Losses on early retirement of debt		(93	)		(57	)		—			—
Other		22			8			10			3

Other, net	$	367		$	325		$	67		$	8

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

(b)

Includes the elimination of NDT fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income taxes related to all NDT fund activity for those units. See Note 11 of the 2009 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)	Primarily includes interest income at ComEd from the 2009 re-measurement of income tax uncertainties. See Note 10 of the 2009 Form 10-K for additional information.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009.

103

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009:


Nine Months Ended September 30, 2010	Exelon			Generation			ComEd			PECO
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	435		$	202		$	161		$	35
Provision for uncollectible accounts		92			—			44			48
Stock-based compensation costs		35			—			—			—
Other decommissioning-related activity(a)		(46	)		(46	)		—			—
Energy-related options(b)		(54	)		(54	)		—			—
Amortization of regulatory asset related to debt costs		18			—			15			3
Accrual for Illinois utility distribution tax refund(c)		(25	)		—			(25	)		—
Under-recovered uncollectible accounts, net(d)		(36	)		—			(36	)		—
ARP SO2 allowances impairment		57			57			—			—
Other		(8	)		5			3			(1	)

Total other non-cash operating activities	$	468		$	164		$	162		$	85

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		154			—			151			3
Other current assets		(81	)		(46	)		10			(51	)(e)
Other noncurrent assets and liabilities		(114	)		(6	)		(247	)(f)		84

Total changes in other assets and liabilities	$	(41	)	$	(52	)	$	(86	)	$	36


Nine Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	404		$	180		$	146		$	36
Loss in equity method investments		21			2			—			19
Provision for uncollectible accounts		121			4			63			54
Stock-based compensation costs		54			—			—			—
Other decommissioning-related activity(a)		(143	)		(143	)		—			—
Energy-related options(b)		37			37			—			—
Asset retirement obligation reduction		(47	)		(47	)		—			—
Amortization of regulatory asset related to debt costs		19			—			16			3
Amortization of the regulatory liability related to the PURTA tax settlement		(2	)		—			—			(2	)
Other-than-temporary impairment to Rabbi trust investments(g)		7			—			7			—
Other		(7	)		(4	)		3			(3	)

Total other non-cash operating activities	$	464		$	29		$	235		$	107

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		38			—			35			3
Other current assets		(51	)		1			1			(45	)(e)
Other noncurrent assets and liabilities		(83	)		5			(58	)(f)		(35	)

Total changes in other assets and liabilities	$	(96	)	$	6		$	(22	)	$	(77	)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(a)

Includes the elimination of NDT fund related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 11 of the 2009 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b)	Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of the underlying transactions.

(c)

During the second quarter of 2010, ComEd recorded a reduction of $25 million to taxes other than income to reflect management’s estimate of future refunds for the 2008 and 2009 tax years associated with Illinois’ utility distribution tax based on an analysis of past refunds and interpretations of the Illinois Public Utility Act. Historically, ComEd has recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now has sufficient, reliable evidence to record and support an estimated receivable associated with the anticipated refund for the 2008 and 2009 tax years.

(d)

Includes $70 million of under-recovered uncollectible accounts expense from 2008 and 2009 recorded in the first quarter of 2010 as well as subsequent adjustments to and amortization of the associated regulatory asset. ComEd is recovering these costs through a rider mechanism authorized by the ICC. See Note 3 — Regulatory Matters for additional information regarding the Illinois legislation for recovery of uncollectible accounts.

(e)	Relates primarily to prepaid utility taxes.

(f)	Relates primarily to a decrease in interest payable associated with a change in uncertain income tax positions. See Note 10 — Income Taxes for additional information.

(g)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009.

Supplemental Balance Sheet Information

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of September 30, 2010 and December 31, 2009:


September 30, 2010	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	9,801	(a)	$	4,757	(a)	$	2,318	$	2,506
Accounts receivable:
Allowance for uncollectible accounts		253			31			99		123

December 31, 2009	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	9,023	(b)	$	4,214	(b)	$	2,129	$	2,442
Accounts receivable:
Allowance for uncollectible accounts		225			31			77		117

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,557 million.

(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,383 million.

105

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information about accumulated OCI (loss) recorded (after tax) within the consolidated Balance Sheets of the Registrants as of September 30, 2010 and December 31, 2009:


September 30, 2010	Exelon			Generation		ComEd		PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	747		$	1,455	$	—	$	—
Pension and non-pension postretirement benefit plans		(2,575	)		—		—		—

Total accumulated other comprehensive income (loss)	$	(1,828	)	$	1,455	$	—	$	—


December 31, 2009	Exelon			Generation		ComEd		PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	551		$	1,157	$	—	$	1
Pension and non-pension postretirement benefit plans		(2,640	)		—		—		—

Total accumulated other comprehensive income (loss)	$	(2,089	)	$	1,157	$	—	$	1

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

During the first quarter of 2010, Exelon and Generation concluded that Generation no longer operates as a single reportable segment, primarily due to a change in the financial information regularly evaluated by the chief operating decision maker (CODM) in determining resource allocation and assessing performance. Certain regional results of Generation’s power marketing activities are now being provided to the CODM and in other public disclosures. As a result, beginning in the first quarter of 2010, Generation has three reportable segments consisting of the Mid-Atlantic, Midwest and South regions. Consequently, Exelon has five reportable segments consisting of Mid-Atlantic, Midwest, South, ComEd and PECO. Prior period presentation has been adjusted for comparative purposes.

Mid-Atlantic represents Generation’s operations primarily in Pennsylvania, New Jersey and Maryland; Midwest includes operations in Illinois and Indiana; and South includes operations primarily in Texas, Georgia and Oklahoma. Exelon and Generation evaluate the performance of Generation’s power marketing activities in Mid- Atlantic, Midwest and South based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel 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. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd and PECO. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Fuel expense includes the fuel costs for internally generated energy. Generation’s retail gas, proprietary trading, other revenue and mark-to-market activities are not allocated to a region. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

ComEd and PECO each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to their similar economic characteristics and the regulatory environments in which they operate. Exelon evaluates the performance of ComEd and PECO based on net income.

106

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2010 and 2009 is as follows:

Three Months Ended September 30, 2010 and 2009


	Generation(a)		ComEd		PECO		Other			Intersegment Eliminations			Exelon
Total revenues(b):
2010	$	2,655	$	1,918	$	1,495	$	183		$	(960	)	$	5,291
2009		2,445		1,475		1,327		179			(1,087	)		4,339
Intersegment revenues(c):
2010	$	778	$	—	$	1	$	183		$	(959	)	$	3
2009		911		1		1		178			(1,088	)		3
Net income (loss):
2010	$	605	$	121	$	127	$	(8	)	$	—		$	845
2009		657		46		92		(39	)		1			757
Total assets:
September 30, 2010	$	25,050	$	21,301	$	8,715	$	5,342		$	(9,460	)	$	50,948
December 31, 2009		22,406		20,697		9,019		6,088			(9,030	)		49,180

(a)

Generation represents the three segments, Mid-Atlantic, Midwest and South as shown below. Intersegment revenues for the three months ended September 30, 2010 and 2009, represent Mid-Atlantic revenue from sales to PECO of $576 million and $562 million, respectively, and Midwest revenue from sales to ComEd of $202 million and $349 million, respectively.

(b)

For the three months ended September 30, 2010 and 2009, utility taxes of $67 million and $64 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2010 and 2009, utility taxes of $80 million and $70 million, respectively, are included in revenues and expenses for PECO.

(c)

The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2 of the 2009 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.


	Mid-Atlantic		Midwest		South			Other(b)		Generation
Total revenues(a):
2010	$	814	$	1,526	$	282		$	33	$	2,655
2009		797		1,388		223			37		2,445
Revenues net of purchased power and fuel expense:
2010(c)	$	564	$	1,044	$	(11	)	$	113	$	1,710
2009		619		1,033		(17	)		128		1,763

(a)	Includes all sales to third parties and affiliated sales to ComEd and PECO. For the three months ended September 30, 2010 and 2009, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.

(b)	Includes retail gas, proprietary trading, other revenue and mark-to-market activities as well as amounts paid related to the Illinois Settlement Legislation.

(c)	In 2010, Other also includes the $57 million lower of cost or market impairment for the ARP SO₂ allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Nine Months Ended September 30, 2010 and 2009


	Generation(a)		ComEd		PECO		Other			Intersegment Eliminations			Exelon
Total revenues(b):
2010	$	7,428	$	4,832	$	4,220	$	542		$	(2,872	)	$	14,150
2009		7,424		4,417		4,045		570			(3,254	)		13,202
Intersegment revenues(c):
2010	$	2,330	$	1	$	4	$	542		$	(2,871	)	$	6
2009		2,687		2		5		569			(3,254	)		9
Net income (loss):
2010	$	1,548	$	246	$	303	$	(58	)	$	—		$	2,039
2009		1,697		275		275		(112	)		(9	)		2,126

(a)

Generation represents the three segments, Mid-Atlantic, Midwest and South as shown below. Intersegment revenues for the nine months ended September 30, 2010 and 2009, represent Mid-Atlantic revenue from sales to PECO of $1,504 million and $1,549 million, respectively, and Midwest revenue from sales to ComEd of $826 million and $1,138 million, respectively.

(b)

For the nine months ended September 30, 2010 and 2009, utility taxes of $147 million and $172 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2010 and 2009, utility taxes of $210 million and $191 million, respectively, are included in revenues and expenses for PECO.

(c)	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 in accordance with regulatory accounting guidance. See Note 3 — Regulatory Issues for additional information on RECs and AECs.


	Mid-Atlantic		Midwest		South			Other(b)		Generation
Total revenues(a):
2010	$	2,344	$	4,259	$	580		$	245	$	7,428
2009		2,484		4,182		569			189		7,424
Revenues net of purchased power and fuel expense:
2010(c)	$	1,760	$	3,054	$	(102	)	$	274	$	4,986
2009		1,995		3,123		(74	)		123		5,167

(a)	Includes all sales to third parties and affiliated sales to ComEd and PECO. For the nine months ended September 30, 2010 and 2009, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.

(b)	Includes retail gas, proprietary trading, other revenue and mark-to-market activities as well as amounts paid related to the Illinois Settlement Legislation.

(c)	In 2010, Other also includes the $57 million lower of cost or market impairment for the ARP SO₂ allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

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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, a utility services holding company, operates through the following principal subsidiaries:

•

Generation, whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.

•

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.

•

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.

Exelon has five reportable segments consisting of the Mid-Atlantic, Midwest and South regions in Generation and ComEd and PECO. See Note 15 of the Combined Notes to Consolidated Financial Statements for segment information.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating 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. All amounts presented below are before the impact of income taxes, except as noted.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. Exelon’s net income was $845 million for the three months ended September 30, 2010 as compared to $757 million for the three months ended September 30, 2009, and diluted earnings per average common share were $1.27 for the three months ended September 30, 2010 as compared to $1.14 for the three months ended September 30, 2009.

Revenue net of purchased power and fuel expense, which is a non-GAAP measure as discussed below, increased by $196 million, primarily due to the impact of favorable weather conditions of $117 million in the ComEd and PECO service territories, higher capacity revenues at Generation of $67 million and increased revenues of $50 million at the utility companies to recover the costs of regulatory required programs, which are offset in operating expenses. Increased revenue net of purchased power and fuel expense was partially offset by a $57 million impairment of SO₂ emissions allowances as a result of changes in market prices related to the U.S. EPA’s proposed Transport Rule.

Operating and maintenance expense increased by $120 million primarily due to a 2009 reduction in Generation’s ARO for the Non-Regulatory Agreement Units of $52 million, higher costs at the utility companies associated with regulatory required programs of $50 million, which are offset in revenue net of purchased power expense, and increased wages and other benefits expense of $37 million. Offsetting the increase were decreased planned nuclear refueling outage costs, excluding Salem, of $26 million.

Depreciation and amortization expense increased by $93 million primarily due to a scheduled increase in CTC amortization expense at PECO of $53 million in accordance with its 1998 Restructuring Settlement and

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increased depreciation expense of $45 million primarily due to ongoing capital expenditures and the change in estimated useful lives associated with the plants subject to shutdowns announced in December 2009. In addition, Generation experienced net NDT gains of $119 million in 2010 compared to $150 million in 2009 for Non-Regulatory Agreement Units as a result of less favorable market performance, and taxes other than income increased across the operating companies by $20 million.

Exelon’s results were also significantly affected by discrete charges recorded in the third quarter of 2009, including $96 million associated with early debt retirements at Generation and Exelon Corporate, and $54 million related to the reversal of benefits associated with investment tax credits as a result of the modified opinion issued by the Illinois Supreme Court in July 2009.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. Exelon’s net income was $2,039 million for the nine months ended September 30, 2010 as compared to $2,126 million for the nine months ended September 30, 2009, and diluted earnings per average common share were $3.08 for the nine months ended September 30, 2010 as compared to $3.21 for the nine months ended September 30, 2009.

Revenue net of purchased power and fuel expense increased by $246 million primarily due to the impact of favorable weather conditions of $151 million in the ComEd and PECO service territories and mark-to-market gains of $273 million from Generation’s hedging activities in 2010 compared to gains of $139 million in 2009. Exelon also benefited from increased capacity revenues of $122 million at Generation and a decrease in costs of $67 million associated with the Illinois Settlement Legislation, primarily at Generation. Further, revenues increased by $108 million at the utility companies to recover the costs of regulatory required programs, which are offset in operating expenses. Offsetting these favorable impacts were unfavorable market and portfolio conditions of $151 million, increased nuclear fuel costs of $87 million, the impact of lower nuclear output of $63 million due to increased planned nuclear outage days and a $57 million impairment of SO₂ emissions allowances related to the U.S. EPA’s proposed Transport Rule.

Operating and maintenance expense decreased by $140 million primarily due to the impact of 2009 activities, including the $223 million impairment of the Handley and Mountain Creek stations and reduced stock compensation costs of $37 million across the operating companies. In addition, ComEd recorded a net reduction of $60 million in operating and maintenance expense resulting from the February 2010 approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism. Decreased operating and maintenance expense was partially offset by higher costs at the utility companies associated with regulatory required programs of $108 million, which are offset in revenue net of purchased power expense, a 2009 reduction in Generation’s ARO of $52 million and incremental costs of $41 million related to storms in the ComEd and PECO service territories.

Depreciation and amortization expense increased by $251 million primarily due to a scheduled increase in CTC amortization expense at PECO of $125 million in accordance with its 1998 Restructuring Settlement and increased depreciation expense of $126 million primarily due to ongoing capital expenditures and the change in estimated useful lives associated with the plants subject to shutdowns announced in December 2009. Exelon’s results were also significantly affected by net NDT gains of $86 million in 2010 compared to $220 million in 2009 for Non-Regulatory Agreement Units as a result of less favorable market performance.

Exelon results for the nine months ended September 30, 2010 were negatively affected by certain income tax-related matters. Exelon recorded a non-cash charge of $65 million (after tax) in 2010 and a non-cash gain of $66 million (after tax) in 2009 for the remeasurement of income tax uncertainties. Exelon also recorded a $65 million (after tax) charge to income tax expense as a result of health care legislation passed in March 2010 that includes a provision that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes.

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For further detail regarding the financial results for the three and nine months ended September 30, 2010, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.

Adjusted (non-GAAP) Operating Earnings. Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2010 were $739 million, or $1.11 per diluted share, compared with adjusted (non-GAAP) operating earnings of $633 million, or $0.96 per diluted share, for the same period in 2009. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2010 were $2,057 million, or $3.10 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,112 million, or $3.19 per diluted share, for the same period in 2009. In addition to net income, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings 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 following table provides a reconciliation between net income as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2010 as compared to the same period in 2009:


	Three Months Ended September 30,
	2010						2009
(All amounts after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income	$	845		$	1.27		$	757		$	1.14

Illinois Settlement Legislation(a)		3			—			11			0.02
Mark-to-Market Impact of Economic Hedging Activities(b)		(99	)		(0.14	)		(77	)		(0.12	)
Unrealized Gains Related to NDT Fund Investments(c)		(60	)		(0.09	)		(87	)		(0.13	)
Retirement of Fossil Generating Units(d)		14			0.02			—			—
Impairment of Certain Emissions Allowances(e)		35			0.05			—			—
John Deere Renewables, LLC Acquisition Costs(f)		1			—			—			—
Decommissioning Obligation(g)		—			—			(32	)		(0.05	)
NRG Energy, Inc. Acquisition Costs(h)		—			—			6			0.01
2009 Restructuring Charges(i)		—			—			(3	)		—
Costs Associated with Early Debt Retirements(j)		—			—			58			0.09

Adjusted (non-GAAP) Operating Earnings	$	739		$	1.11		$	633		$	0.96

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	Nine Months Ended September 30,
	2010						2009
(All amounts after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income	$	2,039		$	3.08		$	2,126		$	3.21

Illinois Settlement Legislation(a)		10			0.01			52			0.08
Mark-to-Market Impact of Economic Hedging Activities(b)		(166	)		(0.25	)		(84	)		(0.12	)
Unrealized Gains Related to NDT Fund Investments(c)		(28	)		(0.04	)		(119	)		(0.18	)
Retirement of Fossil Generating Units(d)		34			0.05			—			—
Impairment of Certain Emissions Allowances(e)		35			0.05			—			—
John Deere Renewables, LLC Acquisition Costs(f)		1			—			—			—
Decommissioning Obligation(g)		—			—			(32	)		(0.05	)
NRG Energy, Inc. Acquisition Costs(h)		—			—			20			0.03
2009 Restructuring Charges(i)		—			—			22			0.03
Costs Associated with Early Debt Retirements(j)		—			—			58			0.09
City of Chicago Settlement with ComEd(k)		2			—			—			—
Non-Cash Charge Resulting From Health Care Legislation(l)		65			0.10			—			—
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(m)		65			0.10			(66	)		(0.10	)
Impairment of Certain Generating Assets(n)		—			—			135			0.20

Adjusted (non-GAAP) Operating Earnings	$	2,057		$	3.10		$	2,112		$	3.19

(a)

Reflects credits issued by Generation and ComEd for the three and nine months ended September 30, 2010 and 2009, respectively, as a result of the Illinois Settlement Legislation (net of taxes of $2 million, $6 million, $7 million and $33 million, respectively). See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s and ComEd’s rate relief commitments.

(b)

Reflects the impact of (gains) for the three and nine months ended September 30, 2010 and 2009, respectively, on Generation’s economic hedging activities (net of taxes of $(64) million, $(107) million, $(49) million and $(54) million, respectively). See Note 7 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(c)

Reflects the impact of gains for the three and nine months ended September 30, 2010 and 2009, respectively, on Generation’s NDT fund investments for Non-Regulatory Agreement Units (net of taxes of $(49) million, $(65) million, $(22) million and $(84) million, respectively). See Note 11 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(d)	Reflects the income statement impact for the three and nine months ended 2009 primarily related to the annual update of Generation’s decommissioning obligation (net of taxes of $(20) million).

(e)

Primarily reflects incremental accelerated depreciation expense for the three and nine months ended September 30, 2010, respectively, associated with the planned retirement of four fossil generating units (net of taxes of $9 million and $22 million, respectively). See Note 9 of the Combined Notes to the Consolidated Financial Statements and “Results of Operations — Generation” for additional detail related to the generating unit retirements.

(f)

Reflects the impairment of certain SO2 emissions allowances in the third quarter of 2010 as a result of declining market prices since the release of the EPA’s proposed Transport Rule (net of taxes of $22 million). See Note 13 of the Combined Notes to the Consolidated Financial Statements for additional information.

(g)	Reflects external costs incurred for the three and nine months ended September 30, 2010 associated with Exelon’s proposed acquisition of John Deere Renewables, LLC. See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

(h)	Reflects external costs incurred for the three and nine months ended September 30, 2009, associated with Exelon’s proposed acquisition of NRG Energy, Inc., which was terminated in July 2009 (net of taxes of $4 million and $14 million, respectively).

(i)	Reflects the impact for the three and nine months ended September 30, 2009, respectively, of the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program (net of taxes of $(2) million and $14 million).

(j)	Reflects costs for the three and nine months ended September 30, 2009, respectively, associated with early debt retirements at Generation and Exelon Corporate (net of taxes of $38 million).

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(k)	Reflects costs recorded in the second quarter of 2010 associated with ComEd’s 2007 settlement agreement with the City of Chicago (net of taxes of $1 million).

(l)

Reflects a non-cash charge to income taxes related to the passage of Federal health care legislation, which includes a provision that reduces the deductibility, for Federal income tax purposes, of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional detail related to the impact of the health care legislation.

(m)

Reflects the impacts for the nine months ended September 30, 2010 and September 30, 2009, respectively, of 2009 and 2010 remeasurements of income tax uncertainties and a 2009 change in state deferred income tax rates (net of taxes on interest expense of $41 million and $(23) million). See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional detail.

(n)	Reflects the impairment of the Handley and Mountain Creek stations recorded during the first quarter of 2009 (net of taxes of $88 million). See “Results of Operations — Generation” for additional detail related to asset impairments.

Outlook for the Remainder of 2010 and Beyond.

Economic and Market Conditions

•

Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular, the prices of natural gas and coal, which drive the wholesale market prices that Generation’s nuclear power plants can command, (2) the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, and (3) the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs. The proposed Transport Rule that was published by the U.S. EPA on July 6, 2010 may also impact long-term wholesale power prices. See Environmental Matters below for further detail.

The use of new technologies to recover natural gas from shale deposits is expected to increase natural gas supply and reserves, which will tend to place downward pressure on natural gas prices and could reduce Exelon’s revenues. Additionally, beginning in late 2008, the weak world economy reduced the international demand for coal, oil and natural gas, and led to sharply lower fossil fuel prices putting downward pressure on electricity prices. The same economic weakness has also resulted in lower demand for electricity, although ComEd and PECO now project slight increases in load demand in 2010 as compared to load declines experienced in 2009.

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impacts of market price volatility. Although Exelon’s hedging policies have helped protect Exelon’s earnings as wholesale market prices have declined, sustained increases in natural gas supply and reserve levels, or a slow recovery of the economy, could result in a prolonged depression of or further decline in commodity prices and in long-term sluggish load demand.

New Growth Opportunities

•

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. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW 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, representing over one half of the planned uprate MW, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remainder will come from additional projects across Generation’s nuclear fleet beginning in 2011 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The

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uprates are being undertaken pursuant to 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.

•

On August 30, 2010, Generation entered into an agreement to acquire the equity interests of John Deere Renewables, LLC, a leading operator and developer of wind power, for approximately $860 million. Under the terms of the agreement, Generation will acquire 735 MWs of installed, operating wind capacity located in eight states. Approximately 75 percent of the operating portfolio is already sold under long-term power purchase arrangements. Additionally, contingent upon the commencement of construction, Generation will pay $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development. Generation also has the opportunity to pursue approximately 1,200 MWs of new wind projects that are in various stages of development. The agreement is contingent upon antitrust clearance and Federal and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the fourth quarter of 2010. On September 30, 2010, Generation issued $900 million of senior notes whose proceeds will be used primarily to fund the anticipated acquisition. If the acquisition agreement is terminated or the acquisition is not completed by March 31, 2011, Generation will be obligated to repurchase $550 million of those notes.

•

On April 22, 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan under which PECO will deploy 600,000 smart meters within three years and deploy smart meters to all of its electric customers over the next 10 years. On April 12, 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum allowable grant under the program, for its SGIG project, Smart Future Greater Philadelphia. The SGIG project has a budget of more than $400 million and includes approximately $7 million related to demonstration projects by two sub-recipients. In total, over the next ten years, PECO is planning to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG from the DOE will be used to reduce the impact of those investments on PECO ratepayers.

Liquidity and Cost Management

•

Exelon is subject to significant ongoing cost pressures during these challenging economic times. Exelon is committed to operating its businesses responsibly and managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Exelon is also committed to an ongoing strategy to make itself more effective, efficient and innovative. In 2009, Exelon launched a company-wide cost management initiative, which combines short-term actions with long-term change. In the short-term, Exelon realized cost savings, primarily as a result of the elimination of 500 positions within BSC and ComEd in 2009, productivity improvements and stringent controls on supply spending, contracting and overtime costs. Exelon is committed to maintaining a cost control focus and expects to largely offset increasing pension and benefits expense and general inflation in 2010 with additional cost savings, including freezing executive salaries and reducing employee benefits. With regard to long-term changes, Exelon is analyzing cost trends over the past five years to identify future cost savings opportunities and implementing more planning and performance-measurement tools that allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.

•

On March 25, 2010, ComEd replaced its $952 million credit facility with a similar $1 billion unsecured revolving credit facility that extends to March 25, 2013. Although the covenants are largely the same as the prior facility, the new facility has higher borrowing costs, reflecting current market pricing. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information regarding those costs. Exelon’s, Generation’s, and PECO’s credit facilities largely extend through October

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2012. These credit facilities currently provide sufficient liquidity to each of the Registrants. Upon maturity of these credit facilities, Exelon, Generation and PECO may not be able to renew or replace these existing facilities at current terms or commitment levels from banks. Consequently, Exelon, Generation, and PECO may face increased costs for liquidity needs in 2011 and may choose to establish alternative liquidity sources as appropriate.

Regulatory Matters

•

On September 30, 2010, the Illinois Appellate Court (Court) issued a decision in the appeals related to the ICC’s order in ComEd’s 2007 electric distribution rate case. That decision ruled against ComEd on the treatment of accumulated post-test year depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). ComEd does not believe any of its other riders are impacted by the Court’s ruling. On October 21, 2010, ComEd filed a petition for rehearing with the Court in connection with the September 30, 2010 ruling. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to the Court’s order.

The following table presents the estimated potential impacts to Exelon’s and ComEd’s 2010 and 2011 pre-tax earnings resulting from the Court’s order.


(Pre-tax in millions)	3rd Quarter 2010			4th Quarter 2010			1/1/11 - 5/31/11(a)
Revenues subject to refund based on Court order(b)	$	—		$	(18	)	$	(30	)
Reduced pre-tax earnings related to Rider SMP		—			(1	)		(7	)
Write-off of Rider SMP Regulatory Asset		(4	)		—			—

(a)

ComEd currently expects new rates will be established in its 2010 distribution rate case by no later than June 2011, at which point in time the impacts of the Court’s decision should be fully incorporated into ComEd’s rates.

(b)

The Court also required the ICC to consider whether an additional three months of net pro forma plant investment, beyond what was approved in the ICC order, should be included in rate base. To the extent the ICC allows ComEd to include an additional three months of net plant additions in its revised rates, the pre-tax Revenues Subject to Refund would be reduced by an estimated $4 million and $8 million, respectively, in the fourth quarter of 2010 and the first five months of 2011.

•

On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its annual service revenue requirement for electric distribution to allow it to continue modernizing its electric delivery system and recover the costs of substantial investments made since the last rate filing in 2007 (2010 Rate Case). The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested rate of return on common equity is 11.5%. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric bill by approximately 7%. In addition, ComEd is requesting future recovery of certain amounts that were previously recorded as expense. If that request is approved, ComEd would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd would recognize a one-time benefit of up to $39 million (pre-tax) to reverse the prior charges. The requested increase also includes $22 million for increased uncollectible accounts expense. If the rate request is approved, the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff would be increased by $22 million. The Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case, discussed above, makes it highly unlikely that the ICC would decide the accumulated post-test year depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $396 million could be reduced by approximately $85 million as a result of this adjustment. The new electric distribution rates would take effect no later than June 2011 unless the effective date is delayed due to the actions resulting from the appeals discussed below.

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ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve. See the discussion of ComEd’s 2007 electric distribution rate case above and in Note 3 of the Combined Notes to Consolidated Financial Statements.

On October 18, 2010, ComEd filed a proposed tariff with the ICC to allow it to recover, through inclusion in the 2010 Rate Case, certain program operating costs originally allowed under Rider SMP that would otherwise be unrecoverable due to the Court’s decision. ComEd has requested the ICC to act on the proposed tariff within the fourth quarter. The Rider SMP pilot program capital investment has already been included in rate base in the 2010 Rate Case. ComEd cannot predict the ICC’s decision in connection with the proposed tariff.

On August 26, 2010, the Illinois Attorney General and certain other intervenors filed separate motions with the ICC to dismiss the 2010 Rate Case on procedural grounds in connection with ComEd’s initial filing on June 30, 2010. On September 17, 2010, the ALJs in the case denied those motions to dismiss. On October 8, 2010, the Coalition to Request Equitable Allocation of Costs Together (REACT) appealed this decision to the ICC (Appeal). On October 15, 2010, ComEd filed with the ICC its opposition to the appeal filed by REACT. There is no specific time period for the ICC to act on the Appeal. The ICC could deny the Appeal or dismiss the 2010 Rate Case. The latter action would cause some delay in the effectiveness of rates that might otherwise become effective in June 2011. The extent of lost revenues for 2011 would depend upon the length of the delay and the amount of the rate increase ultimately approved by the ICC. ComEd cannot predict when the ICC may rule and how much of the requested electric distribution rate increase the ICC may approve. ComEd is continuing to evaluate its options in connection with the Appeal.

•

On August 31, 2010, ComEd filed with the ICC an alternative regulation pilot proposal as a companion proposal to its 2010 Rate Case under a provision of the Illinois Public Utility Act that contemplates an alternative regulatory structure. Rather than employing the traditional rate setting process in which the utility seeks recovery of costs already incurred, the proposal, if approved, would bring utilities, stakeholders, and the ICC together to develop, review and approve ongoing investment programs before those investments are made. The pilot process would include a flow-through mechanism to recover the depreciation and the carrying costs associated with an estimated $130 million in capital investments and $65 million in incremental operating and maintenance expense over a two-year period, as incurred. The unrecovered portion of the capital investments would be included in ComEd’s rate base in its next delivery services rate case filing. The ICC proceedings relating to the pilot proposal will occur over a period of up to nine months after filing. The alternative regulatory structure as proposed by ComEd includes an immediate operating and maintenance savings to customers (up to $2 million) and an incentive mechanism for completing the capital investments under budget. This filing includes a request for approval of the alternative regulatory mechanism as well as approval of costs related to electric vehicles, accelerated reinvestment of urban underground facilities and low income assistance. If the mechanism is approved, ComEd would also seek recovery of an estimated $125 million of “smart grid” investments after the conclusion of the Illinois Statewide Smart Grid Collaborative workshops, smart grid policy docket and evaluation of its AMI pilot program. ComEd is continuing to evaluate and cannot predict the impacts, if any, the September 30, 2010 Appellate Court decision may have on the ultimate outcome of this alternative regulation filing.

•

In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with the legislation, with minor modifications. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. Recovery of the regulatory asset associated with 2008 and 2009 activities will take place over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference

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in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund as required by the legislation. The fund is used to assist low-income residential customers.

•

On August 31, 2010, PECO and interested parties filed with the PAPUC a joint petition for partial settlement with respect to PECO’s electric distribution rate case, and a joint petition for full settlement with respect to PECO’s gas distribution rate case. The electric distribution partial settlement reflects an increase of approximately $225 million in annual service revenue, which is approximately 71% of the $316 million originally requested. The issue remaining for resolution in the electric distribution rate case is related to PECO’s Purchase of Electric Generation Supplier Receivables Program and does not impact the amount of the revenue requirement in the settlement. The gas distribution rate case settlement reflects an increase of approximately $20 million in annual service revenue, which is approximately 46% of the $44 million originally requested. The settlements are subject to PAPUC approval, and, if approved, the rate increases will take effect on January 1, 2011.

In accordance with the DSP Program, PECO has completed four competitive procurements for electric supply for default electric service customers commencing January 2011. As of September 30, 2010, PECO has procured substantially all of the total estimated electric supply needed to serve the residential customer class in 2011.

The electric distribution rate case settlement, if approved, and the 2010 electric supply procurement results indicate an increase of 5.1% in the average residential customer total electric bill on January 1, 2011, above current bills.

The gas distribution rate case settlement, if approved, will result in an increase of 3.7% in the average residential customer total natural gas bill on January 1, 2011, above current bills.

Environmental Matters

•

On July 6, 2010, the U.S. EPA published its proposed Transport Rule as the replacement to the CAIR that had been remanded by a Federal court decision due to a number of legal deficiencies. The proposed Transport Rule is the first of a number of significant regulations that the U.S. EPA expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. The air and waste regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement of older, marginal facilities. Due to its low carbon generation portfolio, Generation will not be as significantly affected by these regulations, which would, therefore, result in a comparative advantage for Generation relative to electric generators that are more reliant on fossil-fuel plants. Upon preliminary review, it is expected that implementation of the proposed Transport Rule regulations would tend to have a long-term positive impact on both capacity and energy prices, which would result in a net benefit to Generation’s results of operations and cash flows. Exelon filed comments with the U.S. EPA in support of the proposed Transport Rule on October 1, 2010.

Beginning with the proposed Transport Rule, the air requirements are expected to be implemented through a series of increasingly stringent regulations relating to conventional air pollutants (e.g., NO_x, SO₂ and particulate matter) as well as HAPs (e.g., acid gases, mercury and other heavy metals). Under the proposal, the first phase of the NO_x and SO₂ emissions reductions under the proposed Transport Rule would commence in 2012, with further reductions of SO₂ emissions proposed to become effective in 2014. Established emissions limits will be further reduced as the U.S. EPA finalizes more restrictive NAAQS for ozone and fine particulate matter in the 2010 — 2011 timeframe, which is the preliminary step to establishing or revising emissions limits. Finally, the most restrictive requirements will be imposed by finalization of a new HAP standard for electric generating units, which the U.S. EPA is

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required to complete by November 2011 pursuant to a consent decree settling litigation under the former CAMR. The HAP standard is technology based and will require the installation of the maximum achievable control technology (MACT) by November 2014. The cumulative impact of these regulations could be to require power plant operators to install wet flue gas desulfurization technology for SO₂ and selective catalytic reduction technology for NO_x.

As proposed, the Transport Rule establishes an aggressive, streamlined process that could result in significant capital expenditures for NO_x and SO₂ pollution control equipment for plant operators as early as 2014 -2015. Given its low carbon generation portfolio, Generation does not currently expect the adoption of the rules as proposed to have a significant impact on its future capital spending requirements.

The proposed Transport Rule regulations also would limit the use of allowance trading to achieve compliance, and restrict entirely the use of pre-2012 allowances. Existing SO₂ allowances under the Title IV Acid Rain Program (ARP) would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment of $57 million on its ARP SO₂ allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because proposed Transport Rule regulations would restrict entirely the use of ARP SO₂ allowances beginning in 2012. See Note 13 of the Combined Notes to Consolidated Financial Statements for further detail related to the impairment of SO₂ allowances on Exelon’s results of operations and financial position.

Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion waste (CCW) would be regulated for the first time under the Federal Resource Conservation and Recovery Act. The U.S. EPA is considering several options, including classification of CCW either as a hazardous or non-hazardous waste. Under either option, the U.S. EPA’s intention is the ultimate elimination of surface impoundments as a waste treatment process. For plants affected by the proposed rules, this would result in significant capital expenditures and variable operating and maintenance expenditures to convert to dry handling and disposal systems and installation of new waste water treatment facilities. Exelon anticipates that the only plants in which it has an ownership interest that would be affected by proposed rules would be Keystone and Conemaugh. As a result, Exelon does not currently expect the adoption of the rules as proposed to have a significant impact on its future capital spending requirements and operating costs.

Pursuant to an April 1, 2009 U.S. Supreme Court ruling, the U.S. EPA is also preparing a proposed rule regulating cooling water intake structures under Section 316(b) of the Clean Water Act, and could require some, or all, facilities with once-through cooling systems to be retrofitted with cooling towers. If Exelon is required to install cooling towers at all of its facilities with once-through cooling systems, the impact to capital and variable operating and maintenance expenditures could be material.

•

In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). See Item 1. General Business of Exelon’s 2009 Annual Report on Form 10-K for further discussion of Exelon’s voluntary GHG emissions reductions.

In conjunction with Exelon’s efforts to reduce its own GHG emissions, Exelon supports the passage by the U.S. Congress of comprehensive climate change legislation, including a mandatory, economy-wide cap-and-trade program for GHG emissions that balances the need to protect consumers, business and the economy with the urgent need to reduce GHG emissions in the United States. Numerous bills have been introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards. It is currently unknown when Congress will continue discussion of these bills or other climate change legislation.

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See Note 13 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

Health Care Reform Legislation

•

In March 2010, the Health Care Reform Acts were signed into law. A number of provisions in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to Medicare prescription drug benefits. Although this change does not take effect immediately, the Registrants are required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded charges of $24 million, $11 million and $9 million, respectively. The reduction of these income tax deductions is also estimated to increase Exelon’s total annual income tax expense by approximately $10 million to $15 million. Of this total, Generation’s, ComEd’s and PECO’s annual income tax expense is estimated to increase $5 million to $8 million, $3 million to $4 million and $1 million to $2 million, respectively.

Additionally, the Health Care Reform Acts contain other provisions that will impact Exelon’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Exelon does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. Accordingly, a re-measurement of Exelon’s postretirement benefit obligation is not required at this time. However, Exelon will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position. Exelon will reflect its best estimate of the expected impacts in its annual actuarial measurement at December 31, 2010, which could result in increased postretirement benefit costs in future years. Exelon may consider plan structure changes in future periods to respond to the provisions of the Health Care Reform Acts and optimally manage its employee benefit costs, subject to collective bargaining agreements, where applicable.

Financial Reform Legislation

•

The Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law on July 21, 2010. This financial reform legislation includes a provision that requires over-the-counter derivative transactions to be executed through an exchange or centrally cleared. In addition, the legislation provides an exemption from mandatory clearing requirements for transactions that are used to hedge commercial risk like those utilized by Generation. At the same time, the legislation includes provisions under which the Commodity Futures Trading Commission may impose collateral requirements for transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation, members of Congress adopted report language and issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk. Final rules on major provisions in the legislation, like new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. Generation currently has unsecured credit with various counterparties available for over-the-counter derivative transactions that could require Generation, or its counterparties, to post additional collateral if they are deemed subject to higher margin requirements. The Registrants are currently unable to assess the impact of the financial reform legislation.

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Competitive Markets

•

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 2010 and 2011. 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 currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of September 30, 2010, the percentage of expected generation hedged was 97%-100%, 87%-90% and 62%-65% for 2010, 2011 and 2012, 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 price risk in subsequent years as well. PECO has transferred substantially all of its commodity price risk related to its procurement of electricity to Generation through a PPA that expires on December 31, 2010. Since PECO entered into its PPA with Generation, market prices for energy have generally been higher than the generation rates PECO has paid for purchased power, which represents the rates paid by PECO customers. Generation’s margins on its other sales have therefore generally been higher. The expiration of the PPA with PECO at the end of 2010 will likely result in increases in margins earned by Generation beginning in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA. While Generation’s three-year ratable hedging program considers the expiration of the PPA, the ultimate impact of entering into new power supply contracts will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC. Both PECO and ComEd mitigate exposure to commodity price risk through the recovery of procurement costs from retail customers.

•

Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. 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 57% of Generation’s uranium concentrate requirements from 2010 through 2014 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 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.

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 2009 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies

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and revenue recognition. At September 30, 2010, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2009.

New Accounting Pronouncements

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

Results of Operations

Net Income (Loss) by Registrant


	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2010			2009			Favorable (Unfavorable) Variance			2010			2009			Favorable (Unfavorable) Variance
Generation	$	605		$	657		$	(52	)	$	1,548		$	1,697		$	(149	)
ComEd		121			46			75			246			275			(29	)
PECO		127			92			35			303			275			28
Other(a)		(8	)		(38	)		30			(58	)		(121	)		63

Exelon	$	845		$	757		$	88		$	2,039		$	2,126		$	(87	)

(a)	Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

Results of Operations — Generation


	Three Months Ended September 30,						Favorable (Unfavorabl) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2010			2009			Favorable (Unfavorabl) Variance			2010			2009			Favorable (Unfavorable) Variance
Operating revenues	$	2,655		$	2,445		$	210		$	7,428		$	7,424		$	4
Purchased power and fuel expense		945			682			(263	)		2,442			2,257			(185	)

Revenue net of purchased power and fuel expense(a)		1,710			1,763			(53	)		4,986			5,167			(181	)
Other operating expenses
Operating and maintenance		649			592			(57	)		2,081			2,210			129
Depreciation and amortization		121			74			(47	)		344			223			(121	)
Taxes other than income		57			51			(6	)		175			150			(25	)

Total other operating expenses		827			717			(110	)		2,600			2,583			(17	)

Operating income		883			1,046			(163	)		2,386			2,584			(198	)

Other income and deductions
Interest expense		(37	)		(24	)		(13	)		(109	)		(77	)		(32	)
Equity in losses of investments		—			(1	)		1			—			(2	)		2
Other, net		192			192			—			138			325			(187	)

Total other income and deductions		155			167			(12	)		29			246			(217	)

Income before income taxes		1,038			1,213			(175	)		2,415			2,830			(415	)
Income taxes		433			556			123			867			1,133			266

Net income	$	605		$	657		$	(52	)	$	1,548		$	1,697		$	(149	)

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(a)

Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel 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.

Net Income

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. Generation’s net income decreased primarily due to lower operating revenues, net of purchased power and fuel expense and higher operating and maintenance expense. Lower operating revenues, net of purchased power and fuel expense, were largely due to unfavorable pricing associated with Generation’s PPA with PECO and higher fuel costs; partially offset by increased capacity revenues and favorable market conditions. Higher operating and maintenance expense was primarily due to the absence of ARO reductions that occurred in 2009.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. Generation’s net income decreased primarily due to lower operating revenues, net of purchased power and fuel expense and less favorable NDT fund performance in 2010 compared to 2009, partially offset by lower operating and maintenance expense. Lower operating revenues, net of purchased power and fuel expense, were largely due to unfavorable portfolio and market conditions, decreased nuclear output as a result of more planned refueling outage days in 2010 and higher fuel costs, which were partially offset by increased mark-to-market gains on economic hedging and proprietary trading activities. Lower operating and maintenance expense primarily reflected the impacts of the impairment of certain generating assets in 2009, partially offset by increased nuclear refueling outage costs associated with the higher number of refueling outage days in 2010; and higher expense due to the absence of ARO reductions that occurred in 2009.

Revenue Net of Purchased Power and Fuel Expense

Generation primarily operates in three segments: the Mid-Atlantic, representing operations primarily in Pennsylvania, New Jersey and Maryland; the Midwest, including operations in Illinois and Indiana; and the South, where the most significant operations are located in Texas, Georgia and Oklahoma.

Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd and PECO. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Fuel expense includes the fuel costs for internally-generated energy. Generation’s retail gas, proprietary trading, other revenue and mark-to-market activities are not allocated to a region.

For the three and nine months ended September 30, 2010 and 2009, Generation’s revenue net of purchased power and fuel expense by region were as follows:


	Three Months Ended September 30,						Variance			% Change
	2010			2009			Variance			% Change
Mid-Atlantic(a)(b)	$	564		$	619		$	(55	)		-8.9	%
Midwest(b)		1,044			1,033			11			1.1	%
South		(11	)		(17	)		6			35.3	%

Total electric revenue net of purchased power and fuel expense	$	1,597		$	1,635		$	(38	)		-2.3	%
Trading portfolio		—			(2	)		2			100.0	%
Mark-to-market gains		163			126			37			29.4	%
Other(c)(d)		(50	)		4			(54	)		n.m.

Total revenue net of purchased power and fuel expense	$	1,710		$	1,763		$	(53	)		-3.0	%

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	Nine Months Ended September 30,						Variance			% Change
	2010			2009			Variance			% Change
Mid-Atlantic(a)(b)	$	1,760		$	1,995		$	(235	)		-11.8	%
Midwest(b)		3,054			3,123			(69	)		-2.2	%
South		(102	)		(74	)		(28	)		-37.8	%

Total electric revenue net of purchased power and fuel expense	$	4,712		$	5,044		$	(332	)		-6.6	%
Trading portfolio		25			1			24			n.m.
Mark-to-market gains		273			138			135			97.8	%
Other(c)(d)		(24	)		(16	)		(8	)		-50.0	%

Total revenue net of purchased power and fuel expense	$	4,986		$	5,167		$	(181	)		-3.5	%

(a)	Included in the Mid-Atlantic are the results of generation in New England.

(b)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(c)	Includes retail gas activities and other operating revenues, which includes amounts paid related to the Illinois Settlement Legislation and decommissioning revenues from PECO.

(d)	In 2010, Other also includes the $57 million impairment for the ARP SO₂ allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

Generation’s supply sources by region are summarized below:


	Three Months Ended September 30,				Variance			% Change
Supply source (GWh)	2010		2009		Variance			% Change
Nuclear generation
Mid-Atlantic(a)		12,076		12,349		(273	)		-2.2	%
Midwest		23,675		23,335		340			1.5	%
Fossil, hydro and solar generation
Mid-Atlantic(b)		2,582		2,044		538			26.3	%
Midwest		16		—		16			100.0	%
South		691		645		46			7.1	%
Purchased power(c)
Mid-Atlantic		599		531		68			12.8	%
Midwest		1,774		1,923		(149	)		-7.7	%
South		4,084		4,215		(131	)		-3.1	%
Total supply by region
Mid-Atlantic		15,257		14,924		333			2.2	%
Midwest		25,465		25,258		207			0.8	%
South		4,775		4,860		(85	)		-1.7	%

Total supply		45,497		45,042		455			1.0	%

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	Nine Months Ended September 30,				Variance			% Change
Supply source (GWh)	2010		2009		Variance			% Change
Nuclear generation
Mid-Atlantic(a)		35,544		36,729		(1,185	)		-3.2	%
Midwest		69,352		69,332		20			0.0	%
Fossil, hydro and solar generation
Mid-Atlantic(b)		7,321		6,952		369			5.3	%
Midwest		23		4		19			475.0	%
South		1,120		1,199		(79	)		-6.6	%
Purchased power(c)
Mid-Atlantic		1,476		1,405		71			5.1	%
Midwest		5,256		5,747		(491	)		-8.5	%
South		9,480		10,870		(1,390	)		-12.8	%
Total supply by region
Mid-Atlantic		44,341		45,086		(745	)		-1.7	%
Midwest		74,631		75,083		(452	)		-0.6	%
South		10,600		12,069		(1,469	)		-12.2	%

Total supply		129,572		132,238		(2,666	)		-2.0	%

(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

(b)	Includes generation in New England.

(c)	Includes non-PPA purchases of 1,594 GWh and 1,219 GWh for the three months ended September 30, 2010 and 2009, respectively, and 3,814 GWh and 2,707 GWh for the nine months ended September 30, 2010 and 2009, respectively.

Generation’s sales are summarized below:


	Three Months Ended September 30,				Variance			% Change
Sales (GWh)(a)	2010		2009		Variance			% Change
ComEd(b)		—		3,639		(3,639	)		-100.0	%
PECO		11,976		10,809		1,167			10.8	%
Market and retail(c)		33,521		30,594		2,927			9.6	%

Total electric sales		45,497		45,042		455			1.0	%


	Nine Months Ended September 30,				Variance			% Change
Sales (GWh)(a)	2010		2009		Variance			% Change
ComEd(b)		5,323		13,391		(8,068	)		-60.2	%
PECO		32,247		30,309		1,938			6.4	%
Market and retail(c)		92,002		88,538		3,464			3.9	%

Total electric sales		129,572		132,238		(2,666	)		-2.0	%

(a)	Excludes trading volumes of 1,077 GWh and 1,645 GWh for the three months ended September 30, 2010 and 2009, respectively, and 2,885 GWh and 5,979 GWh for the nine months ended September 30, 2010 and 2009, respectively.

(b)	Represents sales under the 2006 ComEd auction.

(c)	Includes sales under the ComEd RFP, settlements under the ComEd swap and sales of RECs to affiliates.

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The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the three and nine months ended September 30, 2010 as compared to the same periods in 2009.


	Three Months Ended September 30,						% Change
$/MWh	2010			2009			% Change
Mid-Atlantic(a)	$	36.97		$	41.47			-10.9	%
Midwest(a)(b)	$	41.00		$	40.94			0.1	%
South	$	(2.30	)	$	(3.50	)		34.3	%
Electric revenue net of purchased power and fuel expense per MWh(c)	$	35.11		$	36.32			-3.3	%

	Nine Months Ended September 30,						% Change
$/MWh	2010			2009			% Change
Mid-Atlantic(a)	$	39.69		$	44.23			-10.3	%
Midwest(a)(b)	$	40.92		$	41.60			-1.6	%
South	$	(9.62	)	$	(6.13	)		-56.9	%
Electric revenue net of purchased power and fuel expense per MWh(c)	$	36.37		$	38.12			-4.6	%

(a)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(b)

Includes sales to ComEd under its RFP of $118 million (2,907 GWh) and $11 million (397 GWh) and settlements of the ComEd swap of $84 million and $104 million for the three months ended September 30, 2010 and 2009, respectively. Includes sales to ComEd under its RFP of $254 million (7,050 GWh) and $76 million (1,504 GWh) and settlements of the ComEd swap of $234 million and $204 million for the nine months ended September 30, 2010 and 2009, respectively.

(c)	Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the three and nine months ended September 30, 2010 and 2009 and excludes the mark-to-market impact of Generation’s economic hedging activities, trading portfolio and other.

Mid-Atlantic

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The $55 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to unfavorable pricing relating to Generation’s PPA with PECO and higher fuel costs from owned generation.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The $235 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to unfavorable pricing related to Generation’s PPA with PECO. Additionally, increased sales to PECO resulted in less energy available for market and retail sales.

Midwest

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The $11 million increase in revenue net of purchased power and fuel expense in the Midwest was primarily due to increased market and retail sales in the region and higher capacity revenues, partially offset by decreased realized margins in 2010 for the volumes previously sold under the 2006 ComEd auction contracts, as well as increases in the price of nuclear fuel.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The $69 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to decreased realized margins in 2010 for the volumes previously sold under the 2006 ComEd auction contracts, increases in the price of nuclear fuel and unfavorable market conditions. These decreases were partially offset by higher capacity revenues in the region.

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South

In the South, there are certain long-term purchase power agreements that have fixed capacity payments based on unit availability. The extent to which these fixed payments are recovered is dependent on market conditions.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The $6 million increase in revenue net of purchased power and fuel expense in the South was due to increased realized margins due to capacity revenues from a long-term sale agreement that began in 2010, partially offset by unfavorable market conditions.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The $28 million decrease in revenue net of purchased power and fuel expense in the South was due to lower realized margins due to outage activity and unfavorable market conditions, partially offset by capacity revenues from a long-term sale agreement that began in 2010.

Trading Portfolio

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The nine months ended September 30, 2010 included revenue recorded from certain long options in the proprietary trading portfolio.

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 September 30, 2010 Compared to Three Months Ended September 30, 2009. Mark-to-market gains on power hedging activities were $107 million for the three months ended September 30, 2010, including the impact of the changes in ineffectiveness, compared to gains of $89 million for the three months ended September 30, 2009. Mark-to-market gains on fuel hedging activities were $56 million for the three months ended September 30, 2010 compared to gains of $37 million for the three months ended September 30, 2009. See Notes 5 and 7 of the Combined Notes to the Consolidated Financial Statements for information on gains associated with mark-to-market derivatives.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. Mark-to-market gains on power hedging activities were $142 million for the nine months ended September 30, 2010, including the impact of the changes in ineffectiveness, compared to gains of $129 million for the nine months ended September 30, 2009. Mark-to-market gains on fuel hedging activities were $131 million for the nine months ended September 30, 2010 compared to gains of $9 million for the nine months ended September 30, 2009. See Notes 5 and 7 of the Combined Notes to the Consolidated Financial Statements for information on gains associated with mark-to-market derivatives.

Other

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The decrease in other is primarily due to the $57 million impairment for the ARP SO₂ allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold forward recognized during the third quarter of 2010 and further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The decrease in other is primarily due to the $57 million impairment for the ARP SO₂ allowances further described in

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Note 13 of the Combined Notes to the Consolidated Financial Statements and lower margins on retail gas sales. These decreases were partially offset by $64 million in reduced customer credits issued to ComEd and Ameren associated with the Illinois Settlement Legislation further described in Note 3 of the Combine Notes to the Consolidated Financial Statements.

Nuclear Fleet Capacity Factor and Production Costs


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Nuclear fleet capacity factor(a)		95.4	%		94.7	%		94.2	%		94.9	%
Nuclear fleet production cost per MWh(a)	$	15.61		$	15.38		$	17.00		$	15.63

(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The nuclear fleet capacity factor increased primarily due to fewer refueling outage days, excluding Salem outages, during the three months ended September 30, 2010 compared to the same period in 2009. For the three months ended September 30, 2010 and 2009, refueling outage days totaled 19 and 36, respectively. The decrease in refueling outage days is primarily due to the timing of refueling outage activities performed in 2010 compared to 2009. Higher nuclear fuel costs, partially offset by lower plant operating and maintenance expense resulted in higher production cost per MWh for the three months ended September 30, 2010 as compared to the same period in 2009.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The nuclear fleet capacity factor decreased primarily due to more refueling outage days, excluding Salem outages, during the nine months ended September 30, 2010 compared to the same period in 2009. For the nine months ended September 30, 2010 and 2009, refueling outage days totaled 164 and 127, respectively. The increase in refueling outage days is primarily as a result of the 2009 refueling outage at Three Mile Island Generating Station that extended 23 days into 2010. Higher nuclear fuel costs and higher plant operating and maintenance expense resulted in higher production cost per MWh for the nine months ended September 30, 2010 as compared to the same period in 2009.

Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and nine months ended September 30, 2010 compared to the same period in 2009, consisted of the following:


	Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)			Increase (Decrease)
Impairment of certain generating assets(a)	$	—		$	(223	)
2009 restructuring plan severance charges		4			(11	)
Wages and other benefits		20			14
Asset retirement obligation reduction(b)		52			52
Nuclear refueling outage costs, including the co-owned Salem plant		(29	)		32
Pension and non-pension postretirement benefits expense		3			17
Other		7			(10	)

Increase (decrease) in operating and maintenance expense	$	57		$	(129	)

(a)	See Note 4 of the 2009 Form 10-K for further information.

(b)	Reflects the impact of a reduction in the ARO in excess of the related ARC balances for the Non-Regulatory Agreement Units in 2009. See Note 11 — Nuclear Decommissioning for further information regarding the ARO update in 2009.

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Depreciation and Amortization

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The increase in depreciation and amortization expense was primarily due to the change in the estimated useful lives associated with the plant shutdowns announced in December 2009. The change in estimated useful lives further described in Note 9 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $22 million for the three months ended September 30, 2010 compared to the same period in 2009. Additionally, Generation completed a depreciation rate study during the first quarter of 2010, which resulted in a change in depreciation rate. The change in depreciation rate resulted in an increase of $5 million for the three months ended September 30, 2010 compared to the same period in 2009. The remaining increase in depreciation expense primarily reflected higher plant balances due to capital additions and upgrades to existing facilities.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The increase in depreciation and amortization expense was primarily due to the change in the estimated useful lives associated with the plant shutdowns announced in December 2009. The change in estimated useful lives further described in Note 9 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $57 million for the nine months ended September 30, 2010 compared to the same period in 2009. The change in depreciation rate from the study discussed above resulted in an increase of $16 million for the nine months ended September 30, 2010 compared to the same period in 2009. The remaining increase in depreciation expense primarily reflected higher plant balances due to capital additions and upgrades to existing facilities.

Taxes Other Than Income

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in taxes other than income was primarily due to increased property taxes related to Generation’s nuclear facilities.

Interest Expense

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The increase in interest expense was primarily due to a net increase in long-term debt outstanding as a result of issuances in 2009, further described in Note 9 of the 2009 Form 10-K. The increase in long-term debt resulted in higher interest expense of approximately $8 million for the three months ended September 30, 2010 compared to the same period in 2009. Also Generation recorded a $5 million loss on derivative instruments used to lock in the interest rate associated with the $900 million debt issuance in September 2010 further described in Note 7 of the Combined Notes to Consolidated Financial Statements.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The increase in interest expense was primarily due to a net increase in long-term debt outstanding as a result of issuances in 2009, further described in Note 9 of the 2009 Form 10-K. The increase in long-term debt resulted in higher interest expense of approximately $27 million for the nine months ended September 30, 2010 compared to the same period in 2009. Also Generation recorded a $5 million loss on derivative instruments used to lock in the interest rate associated with the $900 million debt issuance in September 2010 further described in Note 7 of the Combined Notes to Consolidated Financial Statements.

Other, Net

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. Other, net primarily reflects the change in net unrealized gains related to the NDT funds of the Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $70 million of income in 2010 compared to $102 million of income in 2009 related to the contractual elimination of income tax expense associated with the NDT funds of the Regulatory Agreement Units; and costs related to long-term debt extinguished in September 2009 further described in Note 9 of the 2009 Form 10-K.

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Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The decrease in other, net primarily reflects the change in net unrealized gains related to the NDT funds of the Non-Regulatory Agreement Units as described in the table below. The decrease in other, net also reflects $48 million of income in 2010 compared to $154 million of income in 2009 related to the contractual elimination of income tax expense associated with the NDT funds of the Regulatory Agreement Units; and costs related to long-term debt extinguished in September 2009 further described in Note 9 of the 2009 Form 10-K.

The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in other, net for the three and nine months ended September 30, 2010 and 2009:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Net unrealized gains on decommissioning trust funds	$	107	$	153		$	48	$	204
Net realized gains (losses) on sale of decommissioning trust funds	$	1	$	(14	)	$	1	$	(21	)

Effective Income Tax Rate

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The effective income tax rate was 41.7% and 35.9% for the three and nine months ended September 30, 2010, respectively, compared to 45.8% and 40.0% for the same periods during 2009. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.

Results of Operations — ComEd


	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2010			2009			Favorable (Unfavorable) Variance			2010			2009			Favorable (Unfavorable) Variance
Operating revenues	$	1,918		$	1,475		$	443		$	4,832		$	4,417		$	415
Purchased power expense		1,112			776			(336	)		2,636			2,373			(263	)

Revenue net of purchased power expense(a)		806			699			107			2,196			2,044			152

Other operating expenses
Operating and maintenance		298			273			(25	)		733			796			63
Operating and maintenance for regulatory required programs		22			19			(3	)		62			44			(18	)
Depreciation and amortization		126			125			(1	)		386			371			(15	)
Taxes other than income		81			79			(2	)		188			215			27

Total other operating expenses		527			496			(31	)		1,369			1,426			57

Operating income		279			203			76			827			618			209

Other income and deductions
Interest expense, net		(82	)		(82	)		—			(300	)		(241	)		(59	)
Other, net		3			(19	)		22			14			67			(53	)

Total other income and deductions		(79	)		(101	)		22			(286	)		(174	)		(112	)

Income before income taxes		200			102			98			541			444			97
Income taxes		79			56			(23	)		295			169			(126	)

Net income	$	121		$	46		$	75		$	246		$	275		$	(29	)

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(a)

ComEd evaluates its operating performance using the measure of revenue net of purchased power expense. ComEd believes that revenue net of purchased power expense is a useful measurement 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 its discussion of revenue net of purchased power expense 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.

Net income

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. ComEd’s net income for the three months ended September 30, 2010 was higher than the same period in 2009 primarily due to higher revenue net of purchased power expense resulting from favorable weather conditions and increased Other, net resulting from the third quarter 2009 reversal of interest income originally recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court decision granting Illinois investment tax credits to ComEd.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. ComEd’s net income for the nine months ended September 30, 2010 was lower than the same period in 2009 primarily due to the remeasurement of uncertain income tax positions in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. These remeasurements resulted in increased interest expense and income tax expense recorded in the second quarter of 2010, and increased interest income recorded in the second quarter of 2009. Net income was also reduced by higher incremental storm costs, and the first quarter 2010 impact of Federal health care legislation signed into law in March 2010. These reductions to net income were partially offset by higher revenue net of purchased power expense due to favorable weather conditions, a net reduction in operating and maintenance expense resulting from the February 2010 approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism, lower taxes other than income taxes, reflecting the accrual of estimated future refunds recorded in the second quarter of 2010 of the Illinois utility distribution tax for the 2008 and 2009 tax years.

Operating revenues and purchased power expense

There are certain drivers to revenue that are fully offset by their impact on purchased power expense, such as commodity procurement costs and customer choice programs. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on electric revenue net of purchased power expense. See Note 3 of the Combined Notes to the Consolidated Financial Statements and Note 2 of the 2009 Form 10-K for additional information on ComEd’s electricity procurement process.

Electric revenues and purchased power expense are equally affected by fluctuations in customers’ purchases from competitive electric generation suppliers. All ComEd customers have the ability to purchase electricity from an alternative electric generation supplier. The customer choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied electricity. The number of retail customers purchasing electricity from competitive electric generation suppliers was 61,800 and 51,800 at September 30, 2010 and 2009, respectively, representing 2% and 1% of total retail customers, respectively.

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The changes in ComEd’s electric revenue net of purchased power expense for the three and nine months ended September 30, 2010 compared to the same periods in 2009 consisted of the following:


	Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
	Increase (Decrease)		Increase (Decrease)
Weather — delivery	$	72	$	83
Uncollectible accounts recovery		26		43
Energy efficiency and demand response programs and other programs		3		18
Rider SMP Revenues		6		10
Volume — delivery		—		5
Other		—		(7	)

Total increase	$	107	$	152

Weather — delivery

Revenues net of purchased power expense were higher in the three and nine months ended September 30, 2010 compared to the same periods in 2009 due to favorable weather conditions. 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.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service territory. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30, 2010 and 2009, consisted of the following:


							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Three Months Ended September 30,
Heating Degree-Days		70		77		110		(9.1	)%		(36.4	)%
Cooling Degree-Days		854		412		624		107.3	%		36.9	%

Nine Months Ended September 30,
Heating Degree-Days		3,699		4,165		4,084		(11.2	)%		(9.4	)%
Cooling Degree-Days		1,166		589		848		98.0	%		37.5	%

Uncollectible Accounts Recovery

In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. Recovery began in April 2010, and during the three and nine months ended September 30, 2010, ComEd recognized recovery of $26 million and $43 million, respectively, associated with this rider mechanism. These amounts were offset by an equal amount of amortization of regulatory assets reflected in operating and maintenance expense.

131

Energy efficiency and demand response programs

As a result of the Illinois Settlement Legislation, utilities are required to provide energy efficiency and demand response programs and other programs, 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 nine months ended September 30, 2010, ComEd recognized $22 million and $62 million of revenue associated with these programs, respectively. During the three and nine months ended September 30, 2009, ComEd recognized $19 million and $44 million of revenue associated with these programs, respectively. These amounts were offset by equal amounts in operating and maintenance expense for regulatory required programs.

Rider SMP Revenues

In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers via a rider (Rider SMP). During the three and nine months ended September 30, 2010, ComEd recognized $6 million and $10 million of revenue associated with this program, respectively. These amounts were offset by operating and maintenance expense and depreciation expense of $8 million and $11 million for the three and nine months ended September 30, 2010, which included a $4 million write off of the associated regulatory asset in the third quarter of 2010 as a result of the September 30, 2010 ruling by the Illinois Appellate Court. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information on the Appellate Court ruling.

Volume — delivery

Revenues net of purchased power expense increased as a result of higher delivery volume, exclusive of the effects of weather, reflecting customer growth and increased average usage per customer for the three and nine months ended September 30, 2010, compared to the same periods in 2009.

Other

Other revenues were lower during the nine months ended September 30, 2010 compared to the same period in 2009. Other revenues primarily include transmission revenues, late payment charges, rental revenues, mutual assistance and recoveries of environmental remediation costs associated with MGP sites.

Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and nine months ended September 30, 2010 compared to the same periods in 2009, consisted of the following:


	Three Months Ended September 30			Nine Months Ended September 30
	Increase (Decrease)			Increase (Decrease)
Changes in under-recovered uncollectible accounts(a)	$	13		$	34
Storm-related costs		8			20
Rider SMP regulatory asset(b)		8			9
Wages and other benefits		1			(8	)
Corporate allocations		(3	)		(10	)
Contracting		3			(11	)
2009 restructuring plan severance charges		—			(18	)
Uncollectible account expense(c)		(10	)		(19	)
2010 ICC Order(d)		—			(60	)
Other		5			—

Increase (Decrease) in operating and maintenance expense	$	25		$	(63	)

132

(a)

In the three and nine months ended September 30, 2010, ComEd recovered $26 million and $43 million, respectively, of operating revenues through its uncollectible accounts expense rider mechanism. An equal amount of amortization of regulatory assets was recorded in operating and maintenance expense. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

(b)

In the three and nine months ended September 30, 2010, ComEd recorded $8 million and $9 million, respectively, of expenses associated with Rider SMP as well as $0 million and $2 million, respectively, of depreciation expense. These expenses include a third quarter 2010 write off of the associated regulatory asset of $4 million as a result of the September 30, 2010 Illinois Appellate Court ruling. In the three and nine months ended September 30, 2010, ComEd recorded $6 million and $10 million, of operating revenues associated with Rider SMP. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information on the Appellate Court ruling.

(c)	Uncollectible accounts expense decreased for the three and nine months ended September 30, 2010 compared to the same periods in 2009 as a result of ComEd’s increased collection activities.

(d)

On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with Illinois legislation providing public utilities the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism starting with 2008 and prospectively. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense for the cumulative-under collections in 2008 and 2009. In addition, ComEd recorded a one time contribution of $10 million associated with this legislation.

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. See Note 3 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 nine months ended September 30, 2010 compared to the same periods in 2009 primarily due to higher depreciation expense reflecting higher plant balances.

Taxes Other Than Income

Three Months Ended September 30, 2010, Compared to Three Months Ended September 30, 2009. Taxes other than income taxes increased during the three months ended September 30, 2010 compared to the same period in 2009 as a result of increased franchise taxes due to higher volumes sold in 2010.

Nine Months Ended September 30, 2010, Compared to Nine Months Ended September 30, 2009. Taxes other than income taxes decreased during the nine months ended September 30, 2010 compared to the same period in 2009 reflecting the accrual of estimated future refunds of Illinois utility distribution tax recorded in the second quarter of 2010 for the 2008 and 2009 tax years. Historically, ComEd has recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now has sufficient, reliable evidence to record and support an estimated receivable associated with the anticipated refund for the 2008 and 2009 tax years.

Interest Expense, Net

Interest expense increased during the nine months ended September 30, 2010 compared to the same period in 2009 primarily due to $59 million of interest expense associated with the remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets recorded in the second quarter of 2010. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information.

133

Other, Net

Three Months Ended September 30, 2010, Compared to Three Months Ended September 30, 2009. Other, net increased for the three months ended September 30, 2010 compared to the same period in 2009 primarily due to the third quarter 2009 reversal of $29 million of interest income originally recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court decision granting Illinois investment tax credits to ComEd. See Note 10 of the 2009 Form 10-K for additional information.

Nine Months Ended September 30, 2010, Compared to Nine Months Ended September 30, 2009. Other, net decreased for the nine months ended September 30, 2010 compared to the same period in 2009 primarily due to $60 million of interest income recorded in the second quarter of 2009 for uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets. This decrease was partially offset by an other-than-temporary impairment of $7 million recorded to ComEd’s investment held in Rabbi trusts during the second quarter of 2009. See Note 10 of the 2009 Form 10-K for additional information.

Effective Income Tax Rate

The effective income tax rate was 39.5% for the three months ended September 30, 2010 compared to 54.9% for the same period during 2009. The effective income tax rate was 54.5% for the nine months ended September 30, 2010 compared to 38.1% for the same period during 2009. The decrease in the effective income tax rate in the three months ended September 30, 2010 is primarily due to the third quarter 2009 reversal of an Illinois Supreme Court decision granting Illinois investment tax credits to ComEd. The increase in the effective income tax rate for the nine months ended September 30, 2010 is primarily due to the remeasurement of uncertain income tax positions recorded in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

ComEd Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	Three Months Ended September 30,				% Change			Weather- Normal % Change			Nine Months Ended September 30,				% Change			Weather- Normal % Change
Retail Deliveries to customers (in GWhs)	2010		2009		% Change			Weather- Normal % Change			2010		2009		% Change			Weather- Normal % Change
Retail Delivery and Sales(a)
Residential		9,361		6,984		34.0	%		(2.0	)%		22,778		20,079		13.4	%		(0.3	)%
Small commercial & industrial		9,110		8,448		7.8	%		0.8	%		24,975		24,337		2.6	%		(0.3	)%
Large commercial & industrial		7,503		6,922		8.4	%		5.2	%		20,991		20,164		4.1	%		2.9	%
Public authorities & electric railroads		283		287		(1.4	)%		(4.5	)%		927		908		2.1	%		2.3	%

Total Retail		26,257		22,641		16.0	%		1.1	%		69,671		65,488		6.4	%		0.7	%



	As of September 30,
Number of Electric Customers	2010		2009
Residential		3,422,824		3,411,007
Small commercial & industrial		361,424		359,077
Large commercial & industrial		2,014		2,015
Public authorities & electric railroads		5,090		5,030

Total		3,791,352		3,777,129

134


	Three Months Ended September 30,				% Change			Nine Months Ended September 30,				% Change
Electric Revenue	2010		2009		% Change			2010		2009		% Change
Retail Delivery and Sales(a)
Residential	$	1,181	$	797		48.2	%	$	2,788	$	2,374		17.4	%
Small commercial & industrial		471		421		11.9	%		1,273		1,282		(0.7	)%
Large commercial & industrial		109		102		6.9	%		306		294		4.1	%
Public authorities & electric railroads		14		13		7.7	%		48		42		14.3	%

Total Retail		1,775		1,333		33.2	%		4,415		3,992		10.6	%

Other Revenue(b)		143		142		0.7	%		417		425		(1.9	)%

Total Electric Revenues	$	1,918	$	1,475		30.0	%	$	4,832	$	4,417		9.4	%

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy.

(b)	Other revenue primarily includes transmission revenue from PJM. Other items include late payment charges, rental revenue, mutual assistance program revenues and recoveries of environmental remediation costs associated with MGP sites.

Results of Operations — PECO


	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2010			2009			Favorable (Unfavorable) Variance			2010			2009			Favorable (Unfavorable) Variance
Operating revenues	$	1,495		$	1,327		$	168		$	4,220		$	4,045		$	175
Purchased power and fuel		673			651			(22	)		1,987			2,088			101

Revenue net of purchased power and fuel(a)		822			676			146			2,233			1,957			276

Other operating expenses
Operating and maintenance		176			154			(22	)		507			481			(26	)
Operating and maintenance for regulatory required programs		15			—			(15	)		36			—			(36	)
Depreciation and amortization		326			272			(54	)		859			726			(133	)
Taxes other than income		90			78			(12	)		240			213			(27	)

Total other operating expenses		607			504			(103	)		1,642			1,420			(222	)

Operating income		215			172			43			591			537			54

Other income and deductions
Interest expense, net		(38	)		(46	)		8			(160	)		(145	)		(15	)
Loss in equity method investments		—			(6	)		6			—			(19	)		19
Other, net		3			2			1			6			8			(2	)

Total other income and deductions		(35	)		(50	)		15			(154	)		(156	)		2

Income before income taxes		180			122			58			437			381			56
Income taxes		53			30			(23	)		134			106			(28	)

Net income		127			92			35			303			275			28
Preferred security dividends		1			1			—			3			3			—

Net income on common stock	$	126		$	91		$	35		$	300		$	272		$	28

135

(a)

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. 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 net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense 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.

Net Income

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. PECO’s net income increased due to increased electric revenues net of purchased power expense, which was partially offset by increased operating expenses. The increase in electric revenues net of purchased power expense reflected increased CTC recoveries and favorable weather conditions. PECO’s operating expenses increased as a result of higher scheduled CTC amortization expense and increased uncollectible accounts expense.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. PECO’s net income increased due to increased electric revenues net of purchased power expense, which was partially offset by increased operating expenses and interest expense. The increase in electric revenues net of purchased power expense reflected increased CTC recoveries and favorable weather conditions. PECO’s operating expenses increased as a result of higher scheduled CTC amortization expense and higher storm related costs, which were partially offset by decreased uncollectible accounts expense. The increase in interest expense was due to additional expense recorded related to a change in the measurement of uncertain tax positions in accordance with accounting guidance in second quarter 2010. For additional information, see Note 10 of the Combined Notes to the Consolidated Financial Statements.

Operating Revenues, Purchased Power and Fuel Expense

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. There are certain drivers to operating revenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. Gas revenues and fuel expense are affected by fluctuations in natural gas procurement costs. PECO’s purchased natural gas cost rates charged to customers are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates in accordance with the PAPUC’s PGC. Therefore, fluctuations in natural gas procurement costs have no impact on gas revenue net of fuel expense. The average purchased gas cost rate per mmcf was $6.82 and $7.09 for the three months ended September 30, 2010 and 2009, respectively, and $7.91 and $9.21 for the nine months ended September 30, 2010 and 2009, respectively. PECO’s electric generation rates charged to customers are capped until December 31, 2010 in accordance with the 1998 Restructuring Settlement. Under PECO’s full requirements PPA with Generation, purchased power costs are based on the energy component of the rates charged to customers. Electric revenues and purchased power expense fluctuate in relation to customer class usage as each customer class is charged a different capped electric generation rate; however, there is no impact on electric revenue net of purchased power expense.

Electric revenues and purchased power expense are also affected by fluctuations in customer participation in the customer choice program. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. A customer’s choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. The number of retail customers purchasing energy from a competitive electric generation supplier was 21,500 and 22,200 at September 30, 2010 and 2009, respectively, representing 1% and 1% of total retail customers, respectively.

136

The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended September 30, 2010 compared to the same period in 2009 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	45		$	—		$	45
Volume		2			(1	)		1
CTC Recoveries		89			—			89
Regulatory programs cost recovery		17			—			17
Pricing		(3	)		(1	)		(4	)
Other		(2	)		—			(2	)

Total increase (decrease)	$	148		$	(2	)	$	146

The changes in PECO’s operating revenues net of purchased power and fuel expense for the nine months ended September 30, 2010 compared to the same period in 2009 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	77		$	(9	)	$	68
Volume		1			1			2
CTC Recoveries		189			—			189
Regulatory programs cost recovery		40			—			40
Pricing		(3	)		(3	)		(6	)
Other		(17	)		—			(17	)

Total increase (decrease)	$	287		$	(11	)	$	276

Weather

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. 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 winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2010 compared to the same periods in 2009, electric revenues net of purchased power expense were higher due to favorable weather conditions during the second and third quarters of 2010 in PECO’s service territory. The increase was partially offset by the lower gas revenues net of fuel expense primarily as a result of unfavorable weather conditions during the winter months of 2010 compared to 2009.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the three and nine months ended September 30, 2010 compared to the same periods in 2009 and normal weather consisted of the following:


							% Change
Heating and Cooling Degree-Days	2010		2009		Normal		From 2009			From Normal
Three Months Ended September 30,
Heating Degree-Days		—		19		36		(100.0	)%		(100.0	)%
Cooling Degree-Days		1,212		884		939		37.1	%		29.1	%

Nine Months Ended September 30,
Heating Degree-Days		2,710		2,967		3,004		(8.7	)%		(9.8	)%
Cooling Degree-Days		1,798		1,236		1,271		45.5	%		41.5	%

137

Volume

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in electric operating revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2010 compared to the same periods in 2009 reflected the impact of the economic recovery partially offset by energy efficiency initiatives.

CTC Recoveries

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in electric revenues net of purchased power expense as a result of CTC recoveries for the three and nine months ended September 30, 2010 compared to the same periods in 2009 reflected increased deliveries as a result of favorable weather conditions and an increase to the CTC component of the capped generation rates charged to customers, which resulted in a decrease to the energy component and reduced purchased power expense under the PPA. Due to lower than expected sales volume in 2009, the CTC increase was necessary to ensure full recovery of stranded costs during the final year of the transition period that expires on December 31, 2010.

Regulatory Programs Cost Recovery

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in electric revenues relating to regulatory programs for the three and nine months ended September 30, 2010 primarily related to the recovery of $16 million and $38 million in costs related to the energy efficiency program, which includes $2 million and $4 million related to gross receipts taxes, respectively. The increase also reflected the recovery of consumer education program costs of $1 million and $2 million for the three and nine months ended September 30, 2010, respectively. The costs of these programs are recoverable from customers on a full and current basis through approved regulated rates and have been reflected in operating and maintenance for regulatory required programs during the periods. The gross receipts tax revenues are offset by the corresponding gross receipts tax expense included in taxes other than income during the periods.

Pricing

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The decrease in electric revenues net of purchased power expense as a result of pricing for the three and nine months ended September 30, 2010 compared to the same periods in 2009 reflected lower average electric residential rates.

Other

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. For the nine months ended September 30, 2010 compared to the same period in 2009, other revenue net of purchased power and fuel decreased primarily as a result of lower gross receipts tax revenue due to a reduction in the tax rate and decreased late payment fees.

138

Operating and Maintenance Expense

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in operating and maintenance expense for the three and nine months ended September 30, 2010 compared to the same period in 2009, consisted of the following:


	Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)			Increase (Decrease)
Uncollectible accounts expense	$	12		$	(5	)
Storm-related costs		(2	)		21
Severance		2			(3	)
Salaries and other benefits		7			12
Other		3			1

Increase in operating and maintenance expense	$	22		$	26

Uncollectible accounts expense.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The increase in uncollectible accounts expense for three months ended September 30, 2010 compared to the same period in 2009 primarily reflected an increase in the allowance during the third quarter 2010 as a result of higher revenues and receivables due to favorable weather conditions partially offset by lower charge-offs.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The decrease in uncollectible accounts expense for the nine months ended September 30, 2010 compared to the same period in 2009 primarily reflected a decrease in the allowance as a result of lower charge-offs partially offset by higher revenue and receivables due to favorable weather conditions in the summer months.

Operating and Maintenance for Regulatory Required Programs

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. Operating and maintenance expenses related to regulatory required programs consisted of costs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues during the current periods. During the three and nine months ended September 30, 2010, these expenses consisted of $14 million and $34 million related to energy efficiency programs, respectively, and $1 million and $2 million related to consumer education programs, respectively. Operating and maintenance expenses incurred in 2009 related to these programs were deferred in regulatory assets until revenue recovery began in 2010.

Depreciation and Amortization Expense

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in depreciation and amortization expense for the three and nine months ended September 30, 2010 compared to the same periods in 2009 was primarily due to an increase in scheduled CTC amortization of $53 million and $125 million, respectively, in accordance with PECO’s 1998 Restructuring Settlement.

Taxes Other Than Income

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The increase in taxes other than income for the three and nine months ended September 30, 2010 compared to the same periods in 2009 was primarily due to an increase in gross receipts tax expense as a result of higher revenues.

139

Interest Expense, Net

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009. The decrease in interest expense, net for the three months ended September 30, 2010 compared to the same period in 2009 was primarily due to a decrease in interest expense resulting from the retirement of the PETT transition bonds on September 1, 2010. See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. The increase in interest expense, net for the nine months ended September 30, 2010 compared to the same period in 2009 was primarily due to a change in measurement of uncertain tax positions in accordance with accounting guidance. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional information. This increase was partially offset by a decrease in interest expense resulting from the retirement of the PETT transition bonds on September 1, 2010. See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information.

Loss in Equity Method Investments

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. The decrease in the loss in equity method investments was due to the consolidation of PETT in accordance with authoritative guidance for the consolidation of variable interest entities effective January 1, 2010. PETT was dissolved on September 20, 2010. See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information.

Other, Net

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. Other, net for the three and nine months ended September 30, 2010 remained relatively level compared to the same periods in 2009 with the exception of a decrease in interest income related to a change in measurement of uncertain income tax positions in second quarter 2010. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional information.

Effective Income Tax Rate

Three and Nine Months Ended September 30, 2010 Compared to Three and Nine Months Ended September 30, 2009. PECO’s effective income tax rate was 29.4% and 24.6% for the three months ended September 30, 2010 and 2009, respectively, and 30.7% and 27.8% for the nine months ended September 30, 2010 and 2009, respectively. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.

PECO Electric Operating Statistics and Revenue Detail


	Three Months Ended September 30,				% Change			Weather- Normal % Change			Nine Months Ended September 30,				% Change			Weather- Normal % Change
Retail Deliveries to customers (in GWhs)	2010		2009		% Change			Weather- Normal % Change			2010		2009		% Change			Weather- Normal % Change
Retail Delivery and Sales(a)
Residential		4,144		3,506		18.2	%		2.5	%		10,789		9,805		10.0	%		0.9	%
Small commercial & industrial		2,368		2,223		6.5	%		0.1	%		6,545		6,432		1.8	%		(1.9	)%
Large commercial & industrial		4,447		4,301		3.4	%		(1.0	)%		12,397		11,970		3.6	%		0.5	%
Public authorities & electric railroads		228		233		(2.1	)%		(1.8	)%		699		702		(0.4	)%		(0.3	)%

Total Electric Retail		11,187		10,263		9.0	%		0.5	%		30,430		28,909		5.3	%		0.1	%

140



	As of September 30,
Number of Electric Customers	2010		2009
Residential		1,408,239		1,402,712
Small commercial & industrial		156,502		155,942
Large commercial & industrial		3,092		3,103
Public authorities & electric railroads		984		1,085

Total		1,568,817		1,562,842



	Three Months Ended September 30,				% Change			Nine Months Ended September 30,				% Change
Electric Revenue	2010		2009		% Change			2010		2009		% Change
Retail Delivery and Sales(a)
Residential	$	663	$	548		21.0	%	$	1,625	$	1,430		13.6	%
Small commercial & industrial		308		291		5.8	%		827		802		3.1	%
Large commercial & industrial		374		339		10.3	%		1,035		995		4.0	%
Public authorities & electric railroads		20		22		(9.1	)%		67		68		(1.5	)%

Total Retail		1,365		1,200		13.8	%		3,554		3,295		7.9	%

Other Revenue		74		65		13.8	%		194		200		(3.0	)%

Total Electric Revenues	$	1,439	$	1,265		13.8	%	$	3,748	$	3,495		7.2	%

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges and a CTC. For customers purchasing electricity from PECO, revenue should also reflects the cost of energy.

PECO Gas Operating Statistics and Revenue Detail


	Three Months Ended September 30,				% Change			Weather- Normal % Change			Nine Months Ended September 30,				% Change			Weather- Normal % Change
Deliveries to customers (in mmcf)	2010		2009		% Change			Weather- Normal % Change			2010		2009		% Change			Weather- Normal % Change
Retail sales		3,546		3,694		(4.0	)%		(2.3	)%		37,103		39,444		(5.9	)%		1.1	%
Transportation and other		8,501		6,145		38.3	%		35.6	%		23,658		20,128		17.5	%		13.8	%

Total Gas Deliveries		12,047		9,839		22.4	%		21.5	%		60,761		59,572		2.0	%		5.4	%



	As of September 30,
Number of Gas Customers	2010		2009
Residential		446,348		444,244
Commercial & industrial		40,863		40,914

Total Retail		487,211		485,158
Transportation		834		774

Total		488,045		485,932



	Three Months Ended September 30,				% Change			Nine Months Ended September 30,				% Change
Gas revenue	2010		2009		% Change			2010		2009		% Change
Retail Delivery and Sales
Retail sales	$	52	$	55		(5.5	)%	$	451	$	530		(14.9	)%
Transportation and other		4		7		(42.9	)%		21		20		5.0	%

Total Gas Deliveries	$	56	$	62		(9.7	)%	$	472	$	550		(14.2	)%

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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 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, $1 billion and $574 million, respectively. The Registrants’ credit facilities extend through October 2012 for Exelon, Generation and PECO and March 2013 for ComEd. Exelon, Generation, ComEd and PECO utilize their credit facilities to support their commercial paper programs, provide for other 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 and other postretirement benefit 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 delayed or limited and where such recovery takes place over an extended period of time. See Note 6 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 conditions, 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 13 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 estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. Recent pension funding guidance, including the Worker Retiree and Employer Recovery Act of 2008 and guidance released in 2009 by the U.S. Treasury Department, has modified some of those elections and offers some flexibility by providing automatic approval for certain election changes. Additionally, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law on June 25, 2010. Exelon is evaluating this and other available elective pension funding relief to determine its potential impact on Exelon’s funding requirements and strategies.

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For financial reporting purposes, the unfunded status of the plans is updated annually, at December 31. 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 September 30, 2010 by updating the most significant assumptions impacting the obligations and assets, which are the discount rate and current year’s asset performance. Exelon’s pension and postretirement benefit plans experienced combined actual asset returns of approximately 7% and 21% for the nine months ended September 30, 2010 and year ended December 31, 2009, respectively. Also, the assumed discount rate at September 30, 2010 has decreased 87 basis points since December 31, 2009.

Based on these assumptions, Exelon has estimated the unfunded status of the pension and postretirement welfare plans at September 30, 2010 to be $4,460 million and $2,736 million, respectively, representing an increase of $817 million and $554 million, respectively, from December 31, 2009. Exelon has incorporated the estimated reduction in its postretirement welfare obligation resulting from anticipated cost savings related to a new contract with its prescription drug manager, but has not included any impacts that might arise related to the provisions of the Health Care Reform Acts. Management considers various factors when making funding decisions, including actuarially determined minimum contribution requirements under the Employee Retirement Income Security Act (ERISA), as amended, and contributions required to avoid benefit restrictions and at-risk status, as defined by the Pension Protection Act of 2006, for its 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 expects to contribute approximately $954 million to the benefit plans in 2010. Total expected 2010 contributions include an incremental $500 million contribution to Exelon’s largest pension plan made during the third quarter of 2010 not included in estimated contributions at December 31, 2009. This contribution is expected to reduce the amount and volatility of future required pension contributions. Through September 30, 2010, Exelon had made contributions to the benefit plans of $740 million, net of Medicare Part D subsidies of $7 million.

Management has estimated future required pension contributions at September 30, 2010, incorporating the impact of expected 2010 contributions, an assumption for full year 2010 asset returns of 4% and a discount rate of 4.96%. The estimated pension contributions summarized below include ERISA minimum-required contributions, contributions necessary to avoid benefit restrictions and at-risk status, and payments related to the non-qualified pension plans; these estimates do not include any incremental contributions Exelon may elect to make in these future periods or an election to apply the recent pension funding relief:


	2011		2012		2013		2014		2015		Cumulative
Estimated contributions	$	910	$	898	$	830	$	737	$	628	$	4,003

In addition to the pension contributions discussed above, the Registrants expect to contribute an aggregate of approximately $190-225 million annually from 2011 to 2015 to other postretirement benefit plans. These contributions include amounts required under a PAPUC rate order, certain incremental contributions and other payments from corporate assets. Unlike the qualified pension plans, there are no mandated funding requirements for the other postretirement benefit plans other than to pay claims as incurred and to comply with the rate order mentioned above.

Tax Matters

The Registrants’ future cash flows from operating activities may be affected by the following tax matters:

•

In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. Under the terms of the preliminary agreement, Exelon estimates it would make a tax and interest payment of approximately $235 million in 2011 and receive an additional tax refund of approximately $300 million between 2011 and 2014. Also during the third quarter, Exelon and the IRS Appeals failed to reach a settlement with

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respect to the like-kind exchange position and the related substantial understatement penalty. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding potential cash flows impacts of a fully successful IRS challenge to Exelon’s like-kind exchange position.

•

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 Small Business Jobs Act of 2010 was enacted September 27, 2010 and includes an extension of the incentive from the ARRA that allows companies to claim an accelerated depreciation deduction for Federal income tax purposes equal to 50% of the cost basis of certain property placed in service during 2010. Exelon continues to evaluate the impact The Small Business Jobs Act of 2010 will have on Exelon’s cash flows, and currently estimates the impact to be a reduction of Exelon’s 2010 Federal income tax liability of $300-350 million.

•

The IRS anticipates issuing guidance by the end of 2010 or early 2011 on the appropriate tax treatment of repair costs for transmission and distribution assets. With the issuance of this guidance, ComEd and PECO will begin gathering the necessary data to quantify the results and will likely file a request for change in method of tax accounting for repair costs, which would likely result in a substantial cash benefit.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 2010 and 2009:


	Nine Months Ended September 30,						Variance
	2010			2009			Variance
Net income	$	2,039		$	2,126		$	(87	)
Add (subtract):
Non-cash operating activities(a)		2,633			3,105			(472	)
Pension and non-pension postretirement benefit contributions		(740	)		(456	)		(284	)
Income taxes		310			(176	)		486
Changes in working capital and other noncurrent assets and liabilities(b)		(318	)		(311	)		(7	)
Option premiums (paid) received, net		(101	)		(39	)		(62	)
Counterparty collateral received (posted), net		289			380			(91	)

Net cash flows provided by operations	$	4,112		$	4,629		$	(517	)

(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 loss in equity method investments, decommissioning-related items, 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, income taxes and the current portion of long-term debt.

Cash flows provided by operations for the nine months ended September 30, 2010 and 2009 by Registrant were as follows:


	Nine Months Ended September 30,
	2010		2009
Exelon	$	4,112	$	4,629
Generation		2,563		3,155
ComEd		642		711
PECO		919		862

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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 nine months ended September 30, 2010 and 2009 were as follows:

Generation

•

During the nine months ended September 30, 2010 and 2009, Generation had net collections of counterparty collateral of $443 million and $379 million, respectively. Net collections during the nine months ended September 30, 2010 and 2009 were primarily due to market conditions that resulted in favorable changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted or collected from its counterparties. This collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.

•

During the nine months ended September 30, 2010 and 2009, Generation had net payments of approximately $101 million and $39 million, respectively, related to purchases of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

•

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 nine months ended September 30, 2010 and 2009, Generation contributed cash of approximately $16 million and $92 million, respectively.

ComEd

•

During the nine months ended September 30, 2010 and 2009, ComEd’s payables to Generation for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract decreased by $90 million and $83 million, respectively. During the nine months ended September 30, 2010 and 2009, ComEd’s payables to other energy suppliers for energy purchases decreased by $8 million and $65 million, respectively.

•

During the nine months ended September 30, 2010, ComEd posted $153 million of cash collateral to PJM. Prior to the second quarter of 2010, ComEd used letters of credit to cover all PJM collateral requirements.

PECO

•

During the nine months ended September 30, 2010 and 2009, PECO’s payables to Generation under the PPA (decreased) increased by $(16) million and $31 million, respectively. During the nine months ended September 30, 2010 and 2009, PECO’s payables to other energy suppliers for energy purchases increased (decreased) by $2 million and $(41) million, respectively.

•

During the nine months ended September 30, 2010 and 2009, PECO’s prepaid utility taxes increased by $31 million and $43 million, respectively, primarily due to the Pennsylvania Gross Receipts Tax prepayment in March of each year.

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Cash Flows from Investing Activities

Cash flows provided by (used in) investing activities for the nine months ended September 30, 2010 and 2009 by Registrant were as follows:


	Nine Months Ended September 30,
	2010			2009
Exelon	$	(2,037	)	$	(2,384	)
Generation		(1,501	)		(1,497	)
ComEd		(670	)		(591	)
PECO		61			(263	)

Capital expenditures by Registrant for the nine months ended September 30, 2010 and projected amounts for the full year 2010 are as follows:


	Nine Months Ended September 30, 2010			Projected 2010
Generation(a)	$	1,405		$	1,910
ComEd		686			940
PECO		358			501
Other(b)(c)		(67	)		14

Exelon	$	2,382		$	3,365

(a)	Includes nuclear fuel.

(b)	Other primarily consists of corporate operations and BSC.

(c)	Negative capital expenditures for Other relate to the transfer of information technology hardware and software assets from BSC to Generation, ComEd and PECO. Note that the projected 2010 capital expenditures for Other do not include the impact of these asset transfers.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation. Approximately 44% of the projected 2010 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 2010 capital expenditures are a series of planned power uprates across Generation’s nuclear fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.

ComEd and PECO. Approximately 78% and 81% of the projected 2010 capital expenditures at ComEd and PECO, respectively, are for continuing projects to maintain and improve company operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The remaining amounts are for capital additions to support new business, customer growth and AMI and Smart Grid technologies. ComEd and PECO are each continuing to evaluate their total capital spending requirements. ComEd and PECO anticipate that they will fund their capital expenditures with internally generated funds and borrowings.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the nine months ended September 30, 2010 and 2009 by Registrant were as follows:


	Nine Months Ended September 30,
	2010			2009
Exelon	$	(1,350	)	$	(1,142	)
Generation		48			(1,118	)
ComEd		(29	)		(109	)
PECO		(851	)		(361	)

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Debt. See Note 6 of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.

Dividends. Cash dividend payments and distributions during the nine months ended September 30, 2010 and 2009 by Registrant were as follows:


	Nine Months Ended September 30,
	2010		2009
Exelon	$	1,042	$	1,038
Generation		623		1,800
ComEd		225		180
PECO		181		250

Short-Term Borrowings. During the nine months ended September 30, 2010, ComEd repaid $155 million of outstanding borrowings under its credit agreement and issued $65 million of commercial paper. During the nine months ended September 30, 2009, Exelon and PECO repaid $151 million and $95 million of commercial paper, respectively. During the nine months ended September 30, 2009, ComEd incurred $80 million of outstanding borrowings under its credit agreement.

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during the nine months ended September 30, 2010 and 2009 by Registrant were as follows:


	Nine Months Ended September 30,
	2010		2009
Generation	$	3	$	58
ComEd		2		8
PECO(a)		136	$	267

(a)	$135 million and $240 million for the nine months ended September 30, 2010 and 2009, respectively, reflect payments received to reduce the parent receivable.

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 markets and large, diversified credit facilities. The credit facilities include $7.4 billion in aggregate total commitments of which $6.9 billion was available as of September 30, 2010, and of which no financial institution has more than 9% of the aggregate commitments. Exelon, Generation, ComEd and PECO had access to the commercial paper market during the third quarter of 2010. Due to an upgrade in ComEd’s commercial paper rating last year and improvements in the commercial paper market, ComEd has been able to rely on the commercial paper market as a source of liquidity. 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. The Registrants have continued to closely monitor events in the financial markets 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 2009 Annual Report on Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets or significant bank failures.

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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 September 30, 2010, it would have been required to provide incremental collateral of $1,169 million, which is well within its current available credit facility capacities of $4.6 billion. The $1,169 million includes $957 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 $212 million of financial assurances that Generation would be required to provide Nuclear Electric Insurance Limited related to annual retrospective premium obligations. If ComEd lost its investment grade credit rating as of September 30, 2010, it would have been required to provide incremental collateral of $233 million, which is well within its current available credit facility capacity of $739 million, which takes into account commercial paper borrowings as of September 30, 2010. If PECO lost its investment grade credit rating as of September 30, 2010, it would have been required to provide collateral of $8 million pursuant to PJM’s credit policy and could have been required to provide collateral of $54 million related to its natural gas procurement contracts, which is well within PECO’s current available credit facility capacity of $573 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 the issuance of commercial paper and borrowings under its credit facility. 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 6 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

On March 25, 2010, ComEd replaced its $952 million credit facility with a new three-year $1 billion unsecured revolving credit facility that extends to March 25, 2013. Twenty-two banks have commitments in the credit facility. The fees associated with the facility have increased from the fees under the prior facility reflecting current market pricing.

On October 22, 2010, Generation, ComEd and PECO entered into new credit facility agreements totaling $94 million with minority and community banks located primarily within ComEd’s and PECO’s service territories. The credit agreements were in the amounts of $30 million, $32 million and $32 million for Generation, ComEd and PECO, respectively. These agreements will be utilized solely for issuing letters of credit and replaced similar agreements that expired on October 22,2010.

The following table reflects the Registrants’ commercial paper programs and revolving credit agreements at September 30, 2010.


Commercial Paper Programs
Commercial Paper Issuer	Maximum Program Size(a)		Outstanding Commercial Paper at September 30, 2010		Average Interest Rate on Commercial Paper Borrowings for the nine months ended September 30, 2010
Exelon Corporate	$	957	$	—		—
Generation		4,834		—		—
ComEd		1,000		65		0.74	%
PECO		574		—		—

(a)	Equals aggregate bank commitments under revolving credit agreements. See discussion and table below for items affecting effective program size.

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

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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(a)		Facility Draws		Outstanding Letters of Credit		Available Capacity at September 30, 2010				Average Interest Rate on Facility Borrowings for nine months ended September 30, 2010
Borrower	Aggregate Bank Commitment(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper
Exelon Corporate	$	957	$	—	$	8	$	949	$	949		—
Generation		4,834		—		231		4,603		4,603		—
ComEd		1,000		—		196		804		739		0.61	%
PECO		574		—		1		573		573		—

(a)

Excludes $67 million of credit facility agreements arranged with minority and community banks in October 2009, which are solely utilized to issue letters of credit and expired on October 22, 2010. See discussion above regarding $94 million of new credit facilities entered into with minority and community banks on October 22, 2010.

Borrowings under each credit agreement may bear interest at a rate that floats daily based upon a prime rate or at a rate fixed for a specified interest period based upon a LIBOR-based rate. Under the Exelon, Generation and PECO agreements, an adder of up to 65 basis points may be added to the LIBOR-based rate, based upon the credit rating of the borrower. Under the ComEd agreement, adders of up to 137.5 basis points for prime-based borrowings and 237.5 basis points for LIBOR-based borrowings may be added based upon ComEd’s credit rating.

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 nine months ended September 30, 2010:

Exelon

Generation

ComEd

PECO

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At September 30, 2010, the interest coverage ratios at the Registrants were as follows:


	Exelon		Generation		ComEd		PECO
Interest coverage ratio		11.26		25.21		4.57		4.16

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.

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.

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The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, 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, which could include the posting of collateral. Refer to Note 7 of the Combined Notes to the Consolidated Financial Statements for additional information on collateral provisions.

Intercompany Money Pool. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the nine months ended September 30, 2010 are presented in the following table in addition to the net contribution or borrowing as of September 30, 2010:


	Maximum Contributed		Maximum Borrowed		September 30, 2010 Contributed (Borrowed)
BSC	$	—	$	67	$	(22	)
Exelon Corporate		67		N/A		22

Variable-Rate Debt

Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase any outstanding debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as Long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under existing long-term credit facilities.

Generation had letter of credit facilities that expired during the second quarter of 2010, which were used to enhance the credit of variable-rate long-term tax-exempt debt totalling $212 million, with maturities ranging from 2016 — 2034. Generation repurchased the $212 million of tax-exempt debt during June 2010. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous. See Note 6 of the Combined Notes to the Consolidated Financial Statements for further discussion regarding the Registrants’ variable rate debt.

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 NDT 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

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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 Note 11 of the Combined Notes to the Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.

Shelf Registration Statements

Each of the Registrants have current shelf registration statements effective with the SEC that provide for the sale of unspecified amounts of securities. The ability of each Registrant to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the company, its securities ratings and market conditions.

Regulatory Authorizations

As of September 30, 2010, ComEd had $577 million available in long-term debt refinancing authority and $1.1 billion available in new money long-term debt financing authority from the ICC, and PECO had $1.9 billion in long-term debt financing authority from the PAPUC.

As of September 30, 2010, ComEd and PECO had short-term financing authority from FERC that expires on December 31, 2011 of $2.5 billion and $1.5 billion, respectively.

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. See Note 13 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ commitments.

Generation, ComEd and PECO have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.

EXELON GENERATION COMPANY

General

Generation operates in three segments: Mid-Atlantic, Midwest, and South. The operations of all three segments consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations. These segments are discussed in further detail in “EXELON CORPORATION — General” of this Form 10-Q.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to Generation’s results of operations for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

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Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of 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 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 “Other Purchase Obligations” in Note 13 of the Combined Notes to Consolidated Financial Statements.

COMMONWEALTH EDISON COMPANY

General

ComEd operates in a single operating 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.

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Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations

A discussion of items pertinent to ComEd’s results of operations for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 and the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources

ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper and 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 September 30, 2010, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.

See the “EXELON CORPORATION — Liquidity and Capital Resources” and Note 6 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 $225 million on its common stock during the first nine months of 2010.

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.

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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 “Other Purchase Obligations” in Note 13 of the Combined Notes to Consolidated Financial Statements.

PECO ENERGY COMPANY

General

PECO operates in two business segments that are aggregated into one reportable 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 September 30, 2010 compared to three months ended September 30, 2009 and nine months ended September 30, 2010 compared to nine months ended September 30, 2009 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, accounts receivable agreement 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 September 30, 2010, 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.

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Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Credit Matters

A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 13 of the Combined Notes to Consolidated Financial Statements.

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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 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. The following discussion serves as an update to Item 7A-Quantitative and Qualitative Disclosures about Market Risk of the Registrants’ 2009 Annual Report on Form 10-K incorporated herein by reference.

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

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. 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. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electricity, fossil fuel, and other commodities.

Generation

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 2010 through 2012 and the ComEd financial swap contract during 2010 through 2013. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 7 of the Combined Notes to Consolidated Financial Statements.

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 September 30, 2010, the percentage of expected generation hedged was 97%-100%, 87%-90%, and 62%-65% for 2010, 2011 and 2012, 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. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk 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 September 30, 2010 market conditions and hedged position would be a decrease in pre-tax net income of approximately $66 million and $307 million, respectively, for 2011 and 2012. The impact in 2010 is not significant. Power prices sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk 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.

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Proprietary Trading Activities. 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 RMC. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 1,077 GWhs and 2,885 GWhs for the three and nine months ended September 30, 2010, respectively, and 1,645 GWhs and 5,979 GWhs for the three and nine months ended September 30, 2009, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall revenue from energy marketing activities. Trading portfolio activity for the nine months ended September 30, 2010 resulted in pre-tax gains of $25 million due to net mark-to-market gains of $8 million and realized gains of $17 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $140,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the nine months ended September 30, 2010 of $4,986 million, Generation has not segregated proprietary trading activity in the following tables.

Fuel Procurement. Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained primarily 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 57% of Generation’s uranium concentrate requirements from 2010 through 2014 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 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

ComEd

The five-year 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 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 purchase and normal sales exception under derivative accounting guidance. ComEd does not enter into derivatives for speculative or proprietary trading purposes.

For additional information on these contracts, see Note 7 of the Combined Notes to Consolidated Financial Statements.

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. Pursuant to PECO’s PAPUC-approved DSP Program, PECO began to procure electric supply for default service customers in June 2009 for the post-transition period beginning on January 1, 2011 through block contracts and full requirements contracts. PECO’s full requirements contracts and block contracts that are considered derivatives qualify for the

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normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the DSP Program, PECO is permitted to recover its electricity procurement costs from retail customers without mark-up.

PECO has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its long-term price risk in the natural gas market. PECO does not enter into derivatives for speculative or proprietary trading purposes. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

For additional information on these contracts, see Note 7 of the Combined Notes to Consolidated Financial Statements.

Trading and Non-Trading Marketing Activities.

The following detailed presentation of Exelon’s, Generation’s, ComEd’s and PECO’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).

The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s and PECO’s mark-to-market net asset or liability balance sheet position from December 31, 2009 to September 30, 2010. 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 purchase and normal sales contracts. For additional information on the cash flow hedge gains and losses included within accumulated OCI and the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2010 and December 31, 2009 refer to Note 7 of the Combined Notes to Consolidated Financial Statements.


	Generation			ComEd			PECO			Intercompany Eliminations(e)			Exelon
Total mark-to-market energy contract net assets (liabilities) at December 31, 2009(a)	$	1,769		$	(971	)	$	(4	)	$	—		$	794
Total change in fair value during 2010 of contracts recorded in result of operations		497			—			—			—			497
Reclassification to realized at settlement of contracts recorded in results of operations		(219	)		—			—			—			(219	)
Ineffective portion recognized in income		3			—			—			—			3
Reclassification to realized at settlement from accumulated OCI(b)		(715	)		—			—			230			(485	)
Effective portion of changes in fair value — recorded in OCI(c)(f)		1,202			—			—			(389	)		813
Changes in fair value — energy derivatives(d)		—			(156	)		(5	)		159			(2	)
Changes in collateral		(448	)		—			—			—			(448	)
Changes in net option premium paid/(received)		101			—			—			—			101
Other income statement reclassifications(g)		54			—			—			—			54
Other balance sheet reclassifications		(7	)		—			—			—			(7	)

Total mark-to-market energy contract net assets (liabilities) at September 30, 2010(a)	$	2,237		$	(1,127	)	$	(9	)	$	—		$	1,101

(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	For Generation, includes $230 million loss of reclassifications from accumulated OCI to recognize gains in net income for the nine months ended September 30, 2010 related to the settlement of the five-year financial swap contract with ComEd.

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(c)

For Generation, includes $386 million gain on changes in fair value of the five-year financial swap with ComEd for the nine months ended September 30, 2010, and $3 million gain of changes in fair value on the block contracts with PECO for the nine months ended September 30, 2010. During the second quarter of 2010 the block contracts with PECO were designated as normal sales. As such, the mark-to-market balance on Generation’s Consolidated Balance Sheet will be amortized over the term of the contract.

(d)

For ComEd and PECO, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2010, ComEd recorded a $1,127 million regulatory asset related to its mark-to-market derivative liability. Includes $386 million of changes in the fair value and includes $230 million gain of reclassifications from regulatory asset to recognize cost in purchased power expense due to settlements during the nine months ended September 30, 2010 of ComEd’s financial swap with Generation. As of September 30, 2010, PECO recorded a $9 million regulatory asset related to its mark-to-market derivative liability. During the nine months ended September 30, 2010, PECO’s change in fair value includes a $3 million decrease related to the fair value of PECO’s block contracts with Generation. During the second quarter of 2010 PECO’s block contracts were designated as normal sales. As such, the mark-to-market balance on PECO’s Consolidated Balance Sheet will be amortized over the term of the contract.

(e)	Amounts related to the five-year financial swap between Generation and ComEd and the block contracts between Generation and PECO are eliminated in consolidation.

(f)	For Generation, includes $3 million of changes in cash flow hedge ineffectiveness, of which none was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO.

(g)	Includes $54 million of amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of the underlying transactions for the nine months ended September 30, 2010.

Fair Values

The following table present maturity and source of fair value of the Registrants mark-to-market energy contract net assets (liabilities). The tables provide 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 net assets (liabilities). Second, the tables show the maturity, by year, of the Registrants’ energy contract net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 5 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Exelon


	Maturities Within
	2010			2011			2012		2013		2014		2015 and Beyond		Total Fair Value
Normal Operations, qualifying cash flow hedge contracts (a)(c):
Prices provided by external sources	$	173		$	450		$	151	$	70	$	3	$	—	$	847
Prices based on model or other valuation methods		—			1			3		6		1		—		11

Total	$	173		$	451		$	154	$	76	$	4	$	—	$	858

Normal Operations, other derivative contracts (b)(c):
Actively quoted prices	$	(2	)	$	(1	)	$	—	$	—	$	—	$	—	$	(3	)
Prices provided by external sources		(112	)		72			101		50		42		—		153
Prices based on model or other valuation methods		7			38			8		34		5		1		93

Total	$	(107	)	$	109		$	109	$	84	$	47	$	1	$	243

(a)	Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI.

(b)	Mark-to-market gains and losses on other non-trading 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 of $1,395 million at September 30, 2010.

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Generation


	Maturities Within
	2010			2011			2012		2013		2014		2015 and Beyond		Total Fair Value
Normal Operations, qualifying cash flow hedge contracts(a)(c):
Prices provided by external sources	$	173		$	450		$	151	$	70	$	3	$	—	$	847
Prices based on model or other valuation methods		142			469			398		137		1		—		1,147

Total	$	315		$	919		$	549	$	207	$	4	$	—	$	1,994

Normal Operations, other derivative contracts (b)(c) :
Actively quoted prices	$	(2	)	$	(1	)	$	—	$	—	$	—	$	—	$	(3	)
Prices provided by external sources		(112	)		72			101		50		42		—		153
Prices based on model or other valuation methods		7			38			8		34		5		1		93

Total	$	(107	)	$	109		$	109	$	84	$	47	$	1	$	243

(a)	Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. Amounts include a $1,127 million gain associated with the five-year financial swap with ComEd and $5 million gain related to the fair value of the PECO block contracts.

(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 of $1,395 million at September 30, 2010.

ComEd


	Maturities Within														Total Fair Value
	2010			2011			2012			2013			2014		Total Fair Value
Prices based on model or other valuation methods(a)	$	(142	)	$	(459	)	$	(395	)	$	(131	)	$	—	$	(1,127	)

(a)	Represents ComEd’s net liabilities associated with the five-year financial swap with Generation.

PECO


	Maturities Within											Total Fair Value
	2010		2011			2012		2013		2014		Total Fair Value
Prices based on model or other valuation methods(a)	$	—	$	(9	)	$	—	$	—	$	—	$	(9	)

(a)

Represents PECO’s net liabilities associated with its block contracts executed under its DSP Program. Includes $5 million related to PECO’s block contracts with Generation. See Note 7 of the Combined Notes to Consolidated Financial Statements for information regarding the election of the normal purchases and normal sales scope exception for these contracts.

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

The Registrants are exposed to credit-related losses in the event of non-performance by counterparties with whom they that enter into derivative instruments. The credit exposure of derivative contracts, before collateral and netting, is represented by the fair value of contracts at the reporting date. See Note 7 of the Combined Notes to Consolidated Financial Statements for a detail discussion of credit risk, collateral, and contingent related features.

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Generation

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2010. 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 duration 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 RTOs, ISOs and NYMEX and 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 $58 million and $158 million, respectively. See Note 21 of the 2009 Form 10-K for further information.


Rating as of September 30, 2010	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	$	1,736	$	700	$	1,036		—	$	—
Non-investment grade		17		5		12		—		—
No external ratings
Internally rated — investment grade		60		8		52		—		—
Internally rated — non-investment grade		2		—		2		—		—

Total	$	1,815	$	713	$	1,102		—	$	—


	Maturity of Credit Risk Exposure
Rating as of September 30, 2010	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,406	$	330	$	—	$	1,736
Non-investment grade		17		—		—		17
No external ratings
Internally rated — investment grade		37		18		5		60
Internally rated — non-investment grade		2		—		—		2

Total	$	1,462	$	348	$	5	$	1,815


Net Credit Exposure by Type of Counterparty	As of September 30, 2010
Financial institutions	$	340
Investor-owned utilities, marketers and power producers		629
Coal		5
Other		128

Total	$	1,102

ComEd

There have been no significant changes or additions to ComEd’s exposures to credit risk that are described in Item 1A. Risk Factors of Exelon’s 2009 Annual Report on Form 10-K.

See Note 3 of the Combined Notes to the Consolidated Financial Statements for information regarding ComEd’s recently approved tariffs to adjust rates annually through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense.

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PECO

There have been no significant changes or additions to PECO’s exposures to credit risk, including that PECO could be negatively affected if Generation could not perform under the PPA, that are described in Item 1A. Risk Factors of Exelon’s 2009 Annual Report on Form 10-K.

See Note 7 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

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 September 30, 2010, Generation had no cash collateral deposit payments being held by counterparties and Generation was holding $1,396 million of cash collateral deposits received from counterparties, of which $1,395 million of cash collateral deposits was offset against mark-to-market assets and liabilities. As of September 30, 2010, $1 million of cash collateral received were not offset against net derivatives positions, because they were not associated with energy-related derivatives. See Note 13 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

ComEd

As of September 30, 2010, ComEd did not hold any cash or letters of credit for the purpose of collateral from any of the suppliers in association with energy procurement contracts.

PECO

As of September 30, 2010, PECO was not required to post, nor does it hold collateral under its energy and natural gas procurement contracts. See to Note 7 — Derivative Financial Instruments for further discussion.

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RTOs and ISOs (Exelon, Generation, ComEd and PECO)

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 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 (Exelon and Generation)

Generation enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearinghouse acts as the counterparty to each trade. Transactions on 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.

Long-Term Leases (Exelon)

Exelon’s consolidated balance sheets, as of September 30, 2010, included a $622 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases. This investment represents the estimated residual value of leased assets at the end of the respective lease terms of approximately $1.5 billion, less unearned income of $870 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms which are set at prices above the then expected fair market value of the plants. If the lessees do not exercise the fixed purchase options the lessees return the leasehold interests to Exelon and Exelon has the ability to require the lessees to arrange a service contract with a third party for a period following the lease term. In any event, Exelon is subject to residual value risk to the extent the fair value of the assets are less than the residual value. This risk is mitigated by the fair value of the fixed payments under the service contract. The term of the service contract, however, is less than the expected remaining useful life of the plants, and therefore Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. Lessee performance under the lease agreements is 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 long-term leases. Since 2008, the entity providing the credit enhancement for one of the lessees did not meet the credit rating requirements of the lease. Consequently, Exelon has indefinitely extended a waiver and reduction of the rating requirement, which Exelon may terminate by giving 90 days notice to the lessee. Exelon monitors the continuing credit quality of the credit enhancement party.

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 use interest rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital. At September 30, 2010, 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 nine months ended September 30, 2010. This calculation holds all other variable constant and assumes only the discussed changes in interest rates.

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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 September 30, 2010, 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 NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $369 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. 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.

Item 4.

Controls and Procedures

During the third quarter of 2010, 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 September 30, 2010, 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 third quarter of 2010 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 third quarter of 2010, 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.

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Accordingly, as of September 30, 2010, 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 third quarter of 2010 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’ 2009 Annual Report on Form 10-K and (b) Notes 3 and 13 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 September 30, 2010, the Registrants’ risk factors were consistent with the risk factors described in Exelon’s 2009 Annual Report on Form 10-K.

Item 6.

Exhibits


Exhibit No.		Description
2.1		Purchase Agreement dated as of August 30, 2010 by and between Deere & Company and Generation

4.1		Supplemental Indenture dated as of July 12, 2010 between ComEd and BNY Mellon Trust Company of Illinois, as trustee, and D.G. Donovan, as co-trustee (File No. 1-1839, Form 8-K dated August 2, 2010, Exhibit No. 4.1)

4.2		Form of 4.00% Senior Note due 2020 issued by Generation (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.1)

4.3		Form of 5.75% Senior Note due 2041 issued by Generation (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2)

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 September 30, 2010 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

166

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 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)

October 22, 2010

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/ MATTHEW R. GALVANONI
Matthew R. Galvanoni
(Principal Accounting Officer)

October 22, 2010

168

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/ KEVIN J. WADEN
Joseph R. Trpik, Jr.		Kevin J. Waden
Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)		Vice President and Controller (Principal Accounting Officer)

October 22, 2010

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/ JORGE A. ACEVEDO
Jorge A. Acevedo
Vice President and Controller (Principal Accounting Officer)

October 22, 2010

169