SEC Filing | Exelon Corporation

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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.

162

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.

163

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.

164

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.

165

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

167

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

Purchase Agreement

Exhibit 2.1

EXECUTION COPY

PURCHASE AGREEMENT

Dated as of August 30, 2010

by and between

DEERE & COMPANY

and

EXELON GENERATION COMPANY, LLC

TABLE OF CONTENTS


		PAGE

ARTICLE I

DEFINITIONS

Section 1.1	Definitions		1

ARTICLE II

PURCHASE AND SALE OF INTERESTS

Section 2.1	Purchase and Sale of Transferred Interests		14
Section 2.2	Payment of Purchase Price		14
Section 2.3	Closing		14
Section 2.4	Pre-Closing Purchase Price Adjustment		16
Section 2.5	Post-Closing Purchase Price Adjustment		17
Section 2.6	Michigan Wind Projects Earn Out		19
Section 2.7	Seller Contracts		21

ARTICLE III

REPRESENTATIONS AND WARRANTIES REGARDING SELLER

Section 3.1	Due Organization and Good Standing		22
Section 3.2	Authorization of Transaction		22
Section 3.3	Approvals		22
Section 3.4	Ownership of the Transferred Interests		23
Section 3.5	No Conflict or Violation		23
Section 3.6	Brokers’ Fees		23

ARTICLE IV

REPRESENTATIONS AND WARRANTIES REGARDING THE ACQUIRED COMPANIES

Section 4.1	Due Organization and Good Standing		24
Section 4.2	Capital Structure		24
Section 4.3	Financial Statements; No Undisclosed Liabilities		25
Section 4.4	Legal Proceedings		26
Section 4.5	Taxes		26
Section 4.6	Acquired Companies’ Contracts		29
Section 4.7	Compliance With Law		32
Section 4.8	Employees and Employee Benefit Plans		32
Section 4.9	Labor		34


Section 4.10	Personal Property; Sufficiency of Assets	34
Section 4.11	Real Property	34
Section 4.12	Environmental Matters	37
Section 4.13	Intellectual Property	38
Section 4.14	Affiliate Transactions	39
Section 4.15	Insurance	40
Section 4.16	Absence of Certain Changes	40
Section 4.17	Hedging	40
Section 4.18	Indebtedness; Credit Support Arrangements; Outstanding Payment Obligations	41
Section 4.19	Foreign Corrupt Practices Act	41
Section 4.20	Officers and Managers; Bank Accounts	41
Section 4.21	Turbine Warranties	41
Section 4.22	Regulatory Reporting	43
Section 4.23	Project Acquisitions	43
Section 4.24	No Other Representations	44

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF BUYER

Section 5.1	Due Organization and Good Standing	44
Section 5.2	Authorization of Transaction	44
Section 5.3	Approvals	45
Section 5.4	Brokers' Fees	45
Section 5.5	Legal Proceedings	45
Section 5.6	No Conflict or Violation	45
Section 5.7	Acquisition of Interests for Investment	46
Section 5.8	Sufficient Funds	46
Section 5.9	Solvency	46
Section 5.10	Inspections	46
Section 5.11	Tax Status	46
Section 5.12	No Other Representations	46

ARTICLE VI

COVENANTS

Section 6.1	Publicity	47
Section 6.2	Confidentiality; Non-Competition; Non-Solicitation	47
Section 6.3	Conduct of the Acquired Companies' Business	50
Section 6.4	Access to Information	52
Section 6.5	Filings and Authorizations; HSR Act Filing	54
Section 6.6	Replacement of Existing Credit and Other Seller Support	55
Section 6.7	Use of Corporate Name	55
Section 6.8	Employees and Employee Benefits	56
Section 6.9	Transition Services	58


Section 6.10	Intercompany Accounts	58
Section 6.11	Commercially Reasonable Efforts	58
Section 6.12	Tax Matters	59
Section 6.13	Pending Actions	63
Section 6.14	Post-Closing Access; Preservation of Records	63
Section 6.15	Further Assurances	64
Section 6.16	Contracts To Be Terminated	64
Section 6.17	ITC Grant Proceeds	64
Section 6.18	BETC Monetization Proceeds	64
Section 6.19	Development Projects	66
Section 6.20	Cash Management	67
Section 6.21	Title Insurance Policies	67
Section 6.22	Exclusivity	67
Section 6.23	Insurance Policies	68
Section 6.24	Books and Records	68
Section 6.25	Mountain Home Claim Insurance Proceeds	69
Section 6.26	Texas PURPA Litigation	69

ARTICLE VII

CONDITIONS OF PURCHASE

Section 7.1	Conditions to Each Party’s Obligations	70
Section 7.2	Conditions to Obligations of Buyer	71
Section 7.3	Conditions to Obligations of Seller	72

ARTICLE VIII

TERMINATION

Section 8.1	Termination	73

ARTICLE IX

INDEMNIFICATION

Section 9.1	Obligations of Seller	74
Section 9.2	Obligations of Buyer	76
Section 9.3	Calculation of Losses; Final Purchase Price Adjustment; Mitigation	77
Section 9.4	Time for Claims	78
Section 9.5	Third-Party Claims	78
Section 9.6	Exclusive Remedy	80
Section 9.7	No Punitive Damages	80
Section 9.8	No Right To Offset	80
Section 9.9	Risk Allocation	80

iii


ARTICLE X

MISCELLANEOUS

Section 10.1	Assignment; Binding Effect	80
Section 10.2	Choice of Law	81
Section 10.3	Specific Performance; Consent to Jurisdiction	81
Section 10.4	Survival	82
Section 10.5	Notices	83
Section 10.6	Headings	84
Section 10.7	Fees and Expenses	84
Section 10.8	Entire Agreement	84
Section 10.9	Interpretation	84
Section 10.10	Disclosure	85
Section 10.11	Waiver and Amendment	85
Section 10.12	Counterparts; Facsimile Signatures	85
Section 10.13	Third-Party Beneficiaries	85
Section 10.14	Severability	85
Section 10.15	Waiver	85
Section 10.16	Bulk Sales or Transfer Laws	87

Exhibit 1	PRINCIPLES AND METHODOLOGIES
Exhibit 2	FORM OF ASSIGNMENT
Exhibit 3	FORM OF TRANSITION SERVICES AGREEMENT

INDEX OF DEFINED TERMS


2009 Financial Statements		25
2010 Financial Statements		25
Acquired Companies		1
Action		1
Affiliate		1
Aggregate Interim Capital Expenditures For Development Projects		2
Agreement		1
Allocable Share		2
Allocation Schedule		62
Asserted Liability		78
Assignment Agreement		15
Auditor		17
Base Purchase Price		14
Basket		76
Blade Crack Problem		2
Blade Warranty Expiration Dates		42
Blissfield Wind Project		2
Books and Records		2
Burdensome Condition		55
Business		2
Business Day		2
Business Employees		3
Buyer		1
Buyer Actions		3
Buyer Confidential Information		3
Buyer Disclosure Schedule		3
Buyer Fundamental Representations		3
Buyer Indemnified Parties		74
Buyer Required Approvals		45
Buyer’s Knowledge		84
Capital Expenditure Statement		16
Charter Documents		3
Claim Notice		78
Closing		14
Closing Balance Sheet		17
Closing Base Purchase Price		14
Closing Date		15
Closing Net Working Capital		17
Closing Net Working Capital Statement		17
Code		3
Commercial Operation Date		3
Company Employees		3
Company Intellectual Property		38
Completion of Development and Commencement of Construction		3


Confidentiality Agreement		4
Contract		4
Current Assets		5
Current Liabilities		5
Designated Employees		5
Determination Date		20
Development Companies		5
Development Projects		5
Development Projects CAPEX Budget		5
Employee Benefit Plan		5
Employment Offer		57
Encumbrance		6
Environmental Laws		6
Environmental Permits		6
Equipment and Availability Warranty Commencement Dates		42
Equipment and Availability Warranty Expiration Dates		42
ERISA		6
ERISA Affiliate		6
Estimated Closing Net Working Capital		16
Estimated Net Working Capital Statement		16
Existing Credit Support		6
FERC		7
Final Allocation Schedule		62
Final Base Purchase Price		14
Final Certification		65
Final Determination		7
Final Order		7
Financial Statements		25
Fleet		41
GAAP		7
Governmental Entity		7
Harvest II Windfarm Project		7
Hazardous Substance		7
HSR Act		7
Indebtedness		7
Indemnified Party		8
Indemnifying Notice Period		79
Indemnifying Party		8
Independent Engineer		8
Insurance Policies		40
Intellectual Property		8
ITC Grant		8
ITC Grant Proceeds		8
Law		8
Losses		9
Material Adverse Effect		9


Material Contracts			29
Maximum Amount			76
Michigan PPAs			9
Michigan Wind 2 Project			10
Michigan Wind Projects			10
Michigan Wind Property Agreements			10
Monetized			65
NERC			10
Net Working Capital			10
Objection Notice			17
Occupancy Agreements			10
Occupied Real Property			34
Order			10
Oregon BETC			65
Oregon Project Entities			10
Outside Date			73
Outstanding Credit Support			55
Owned Real Property			34
Partially-Owned Group			10
Permits			32
Permitted Encumbrances			10
Person			11
Pre-Closing Period Compensation			70
Production Taxes			11
Prudent Industry Practices			11
Release			12
Representatives			12
Restricted Period			48
S-88 Blades			41
Securities Act			46
Seller			1
Seller Confidential Information			12
Seller Contracts			21
Seller Disclosure Schedule			12
Seller Fundamental Representations			12
Seller Indemnified Parties			76
Seller Intercompany Debt			12
Seller Names and Marks			56
Seller Required Approvals			22
Seller Tax Claims			61
Seller’s Knowledge			84
Survival Expiration Date			82
Suzlon			12
Suzlon Agreements			41
Target Company			1
Target Company Intercompany Debt			12

vii


Target Net Working Capital			12
Tax			12
Tax Credits			13
Tax Return			13
Taxes			12
Termination Notice			56
Texas Project Entities			13
Texas PURPA Action			13
Texas PURPA Litigation			13
Third-Party Debt			13
Total Purchase Price			14
Transfer Taxes			13
Transferred Employees			13
Transferred Interests			1
Transition Services Agreement			15
Treasury Regulations			14
Turbine Supply Agreement			66
TXQF Conditional Pre-Close Refund			69
Vestas			66
Violation			23
Wholly-Owned Group			14
Written Proposal			66

viii

PURCHASE AGREEMENT

THIS PURCHASE AGREEMENT (this “Agreement”), dated as of August 30, 2010, is entered into by and between DEERE & COMPANY, a Delaware corporation (“Seller”), and EXELON GENERATION COMPANY, LLC, a Pennsylvania limited liability company (“Buyer”).

RECITALS

WHEREAS, Seller owns all of the limited liability company interests (the “Transferred Interests”) of John Deere Renewables, LLC, a Delaware limited liability company (“Target Company”);

WHEREAS, Buyer desires to acquire from Seller, and Seller desires to sell, transfer and assign to Buyer, the Transferred Interests, upon the terms and subject to the conditions set forth in this Agreement.

NOW, THEREFORE, in consideration of the premises and the mutual agreements set forth herein, and for other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, the parties hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. For purposes of this Agreement, except as otherwise expressly provided herein or unless the context otherwise requires, the following terms, when used in this Agreement and the Exhibits, Schedules, and other documents delivered in connection herewith, have the meanings assigned to them in this Section 1.1.

“Action” means any action, claim, complaint, investigation, petition, suit, arbitration or other proceeding, whether civil or criminal, in law or in equity before any arbitrator or other Governmental Entity.

“Acquired Companies” means, collectively, the Target Company and each of the Persons comprising the Wholly-Owned Group and the Partially-Owned Group.

“Affiliate” means a Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, a specified Person. A Person shall be deemed to control another Person if such first Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities or other ownership interests, by Contract or otherwise.

“Aggregate Interim Capital Expenditures For Development Projects” means the aggregate amounts actually delivered by Seller or any of its Affiliates (other than the Acquired Companies), by way of capital contribution, loan or otherwise, to any Acquired Company or to any other Person on behalf of any Acquired Company after the date hereof which were used (i) directly or indirectly, to pay any capital expenditures of any Acquired Company reflected on the Development Projects CAPEX Budget; or (ii) to pay capital expenditures related to the Development Projects in excess of the amounts set forth in the Development Projects CAPEX Budget and consented to in writing by Buyer in advance, which consent shall not be unreasonably withheld, conditioned or delayed.

“Allocable Share” means, with respect to any Person and any item of, or with respect to, any Acquired Company, such Person’s allocable share of such item as determined by reference to such Person’s ownership interest in such Acquired Company at the relevant time and the applicable allocation provisions regarding profits and losses provided in the applicable Charter Documents governing such Acquired Company at the relevant time.

“Blade Crack Problem” means any defect or design problem that has caused certain Suzlon S-88 wind turbine blades to crack in the transition area between the cylindrical root section and the maximum chord section, which cracks typically start on the suction side of the blade close to the leading edge and then grow in both chord wise directions, but which cracks are not the result of any outside physical forces such as lightning.

“Blissfield Wind Project” means the wind project under development in Lenawee County, Michigan, by Blissfield Wind Energy, LLC, with a nameplate capacity of 81 megawatts.

“Books and Records” means all books, records, ledgers, reports, plans and files, files and accounts, manuals, documents, correspondence, studies, and other similar materials primarily related to the conduct of the Business of each Acquired Company in paper or electronic form that are maintained by, or for, such Acquired Company; provided, however, that Books and Records do not include any Tax Returns.

“Business” means the business of the Acquired Companies, including (i) the purchase, ownership, development, construction, financing and sale of wind-powered and other electricity generating facilities, including biomass facilities; (ii) operation and maintenance of wind-powered and other electricity generating facilities, including biomass facilities; (iii) the generation and sale of electricity and renewable energy credits in each case from wind-powered electricity generating facilities; (iv) the transmission of electricity from wind-powered electricity generating facilities; and (v) any other related ancillary business of the Acquired Companies.

“Business Day” means any day other than a Saturday or Sunday or any day banks in the State of New York are authorized or required by Law to be closed.

“Business Employees” means all employees of the Acquired Companies and all other employees of Seller or any of its Affiliates whose primary duties relate to the Business.

“Buyer Actions” means all Actions pending as of the Closing Date against the Seller Indemnified Parties relating to or arising in connection with the Business, including Actions with respect to the matters set forth in Section 1.1(a) of the Seller Disclosure Schedule.

“Buyer Confidential Information” means all information related to the Business, including all reports, analyses, notes or other information that contain any such information. Buyer Confidential Information shall not include information that (i) is or becomes available to the public other than as a result of a disclosure by Seller, any Affiliate of Seller, or any of their Representatives in violation of this Agreement; (ii) becomes available to Seller or any of its Representatives from a source other than Buyer or its Representatives, provided that, to Seller’s Knowledge, the source of such information was not bound by a confidentiality agreement with Buyer with respect to such information; or (iii) was or is developed or derived without the aid, application or use of the Buyer Confidential Information.

“Buyer Disclosure Schedule” means the Schedules delivered by Buyer to Seller on the date hereof.

“Buyer Fundamental Representations” means the representations and warranties set forth in Sections 5.1, 5.2, 5.4, 5.6(b) and 5.11.

“Charter Documents” of a Person means the certificate or articles of incorporation, certificate or articles of formation or organization, by-laws, shareholders’ agreement, limited liability company agreement, partnership agreement or other comparable organizational documents, as applicable, of such Person.

“Code” means the Internal Revenue Code of 1986, as amended.

“Commercial Operation Date” has, with respect to any Michigan Wind Project, the meaning set forth in the Michigan PPA related to such Michigan Wind Project.

“Company Employees” means all Business Employees who are employed by the Acquired Companies.

“Completion of Development and Commencement of Construction” for a particular Michigan Wind Project means the earlier of:

(a) the date on which all of the following have been achieved:

(i) the relevant Acquired Company, which owns such Michigan Wind Project, has (1) all of the Occupancy Agreements needed to construct and operate such Michigan Wind Project and such Occupancy

Agreements are in full force and effect, and no default by the applicable counterparties thereto exists that is continuing and is material to such Michigan Wind Project, and (2) all Permits necessary to construct and operate such Michigan Wind Project (except for immaterial Permits and Permits which cannot be obtained until such Michigan Wind Project achieves commercial operation);

(ii) all usual and customary turbine supply agreements, balance of plant agreements and all other material agreements reasonably necessary for commencement of construction of such Michigan Wind Project (including all necessary project related substation and electrical infrastructure subcontracts) have been executed and delivered by the relevant counterparties thereto, and all such agreements are in full force and effect, and no default by the applicable counterparties thereto exists that is continuing and is material to such Michigan Wind Project, and any conditions precedent for proceeding thereunder have been satisfied (except for any such condition, if any, which, by its terms, cannot be satisfied prior to such Michigan Wind Project achieving commercial operation);

(iii) all interconnection agreements necessary to inject the power to be generated by such Michigan Wind Project have been executed and delivered by the relevant counterparties thereto and all such agreements are in full force and effect, and no default by the applicable counterparties thereto exists that is continuing and is material to such Michigan Wind Project, and such agreements allow for the construction of the interconnection facilities pursuant to a schedule that is not in breach of, or inconsistent with, the Michigan PPA related to such Michigan Wind Project;

(iv) the Michigan PPA related to such Michigan Wind Project is in full force and effect, and no default by the applicable counterparties thereto exists thereunder that is continuing and is material to such Michigan Wind Project; and

(v) the applicable Acquired Company has commenced the on-site construction of roads and foundations, and the foundation for the initial wind turbine for such Michigan Wind Project has been constructed; or

(b) the Commercial Operation Date for such particular Michigan Wind Project.

“Confidentiality Agreement” means that certain Confidentiality Agreement by and between Seller and Buyer dated April 5, 2010.

“Contract” means any legally binding contract, agreement, arrangement, bond or bond commitment, instrument, note, mortgage, loan or credit agreement, debenture, security agreement, indenture, deed of trust, lease, purchase order, license or other instrument or agreement of any kind (oral or written).

“Current Assets” means all current assets of the Acquired Companies that would be reflected as current assets on a balance sheet of the Target Company prepared in accordance with GAAP and in conformity with the principles, methodologies and line items set forth on Exhibit 1 hereto, including, without limitation, accounts receivable, prepaid expenses and deposits, and inventory, but excluding any receivables associated with the Target Company Intercompany Debt and all Tax assets.

“Current Liabilities” means all current liabilities of the Acquired Companies that would be reflected as current liabilities on a balance sheet of the Target Company prepared in accordance with GAAP and in conformity with the principles, methodologies and line items set forth on Exhibit 1 hereto, including, without limitation, accounts payable, accrued expenses, accrued compensation and deferred revenue, but excluding all Tax liabilities (other than those denoted as Current Liabilities on Exhibit 1 hereto), liabilities, if any, the responsibility for which is retained by Seller pursuant to this Agreement, and all obligations relating to the Target Company Intercompany Debt and the Seller Intercompany Debt.

“Designated Employees” means the Business Employees other than those Business Employees set forth on Section 1.1(b) of the Seller Disclosure Schedule.

“Development Companies” means Michigan Wind 2, LLC, a Delaware limited liability company, Harvest II Windfarm, LLC, a Delaware limited liability company, Bellevue Wind Energy, LLC, a Delaware limited liability company, and Blissfield Wind Energy, LLC, a Delaware limited liability company.

“Development Projects” means the wind farms and biomass projects under development by (a) the Target Company, (b) any of the Development Companies or (c) Seller or any of its other Affiliates on behalf of the Target Company or any of the Development Companies which have not reached a commercial operation date as of the date of this Agreement and which are described in Section 1.1(c) of the Seller Disclosure Schedule.

“Development Projects CAPEX Budget” means the capital expenditure budget relating to the Development Projects set forth in Section 1.1(d) of the Seller Disclosure Schedule.

“Employee Benefit Plan” means each employee benefit plan (as such term is defined in Section 3(3) of ERISA) and each other employee benefit plan, program or arrangement, including without limitation each deferred compensation, severance, change-in-control, retention, health care, insurance coverage, profit sharing, employee loan, vacation, stock purchase, stock option, equity-based or other equity compensation, incentive and bonus plan, program or arrangement, in each case maintained or sponsored by Seller, the Acquired Companies or any of their respective ERISA Affiliates and in which individuals currently or formerly employed by or on behalf of the Acquired Companies participate or are eligible to participate in connection with such employment or to which any of the Acquired Companies has any obligation to contribute.

“Encumbrance” means any claim, charge, lease, covenant, easement, encumbrance, pledge, security interest, lien, option, pledge, right of others, mortgage, deed of trust, hypothecation, conditional sale, or restriction (whether on voting, sale, transfer, disposition, or otherwise), whether imposed by Contract, understanding or Law, except, in the case of the Transferred Interests, for any restrictions on transfer generally arising under any applicable securities Law.

“Environmental Laws” means any and all Laws pertaining to the prevention of pollution, remediation of contamination or restoration of environmental quality, protection of human health (but only with respect to exposure to Hazardous Substances) or protection of the environment, natural resources and wildlife, including but not limited to the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 1801 et seq.; the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq.; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. § 300f et seq.; the Endangered Species Act, 16 U.S.C. § 1531 et seq.; the Bald Eagle Protection Act, 16 U.S.C. § 668 et seq.; the Migratory Bird Treaty Act, 16 U.S.C. § 703 et seq.; the National Historic Preservation Act, 16 U.S.C. § 470 et seq.; the Superfund Amendments and Reauthorization Act; and the Hazardous and Solid Waste Amendments Act and all similar Laws of any Governmental Entity having jurisdiction over the Acquired Companies.

“Environmental Permits” means written permits, registrations, licenses, certificates, approvals, exemptions, variances, consents and other authorizations required under any Environmental Laws.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and the related regulations and published interpretations.

“ERISA Affiliate” means, with respect to any Person, each business or entity which is, or any time during the six-year period preceding the date hereof was, a member of a “controlled group of corporations,” under “common control” or a member of an “affiliate service group” with such Person within the meaning of Sections 414(b), (c) or (m) of the Code, or required to be aggregated with such Person under Section 414(o) of the Code, or under “common control” with such Person within the meaning of Section 4001(a)(14) of ERISA.

“Existing Credit Support” means all guarantees and letters of credit issued or procured, directly or indirectly, by or for the account of Seller or its Affiliates (other than the Acquired Companies, unless an entity other than an Acquired Company is ultimately responsible therefor), as well as any indemnity, payment or other similar obligations of Seller or its Affiliates (other than the Acquired Companies), in each case relating to contractual commitments or other liabilities of the Acquired Companies or the Business associated therewith.

“FERC” means the Federal Energy Regulatory Commission.

“Final Determination” means (i) a decision, judgment, decree or other order by any court of competent jurisdiction, which decision, judgment, decree or other order has become final after all appeals allowable by Law and hereunder by either party to the applicable Action have been exhausted or the time for filing such appeals has expired; (ii) a closing agreement entered into under Section 7121 of the Code or any other binding settlement agreement entered into in connection with an administrative or judicial proceeding, in each case; (iii) the expiration of the time for instituting a suit with respect to a claimed deficiency; or (iv) the expiration of the time for instituting a claim for refund, or if such a claim was filed, the expiration of the time for instituting suit with respect thereto.

“Final Order” means a written final order that has not been revised, stayed, enjoined, set aside, annulled or suspended, with respect to which any required waiting period has expired, and as to which all conditions to effectiveness prescribed therein or otherwise by Law or any other order of any Governmental Entity have been satisfied; provided that such order shall be final irrespective of whether any rehearing or appeal thereof is pending.

“GAAP” means generally accepted accounting principles in the United States, as in effect from time to time, consistently applied.

“Governmental Entity” means any federal, state, provincial, foreign, tribal or local government or quasi-governmental authority or self-regulatory organization or any agency, bureau, board, commission, court, department, political subdivision, tribunal, authority or other instrumentality thereof.

“Harvest II Windfarm Project” means the wind project under development in Huron County, Michigan, by Harvest II Windfarm, LLC, with a nameplate capacity of 59.4 megawatts.

“Hazardous Substance” means any substance that (i) is or contains asbestos, polychlorinated biphenyls or radon; (ii) is or contains oil or gas exploration or production waste or any petroleum, petroleum hydrocarbons, petroleum products, natural gas, crude oil, and any components, fractions, or derivatives thereof; (iii) requires investigation, removal or remediation under any Environmental Law, or is defined, listed or identified as a “hazardous waste,” “hazardous substance,” “toxic substance,” “pollutant,” or “contaminant” thereunder; or (iv) whether by its nature or its use, is regulated by any Environmental Law.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the related regulations and published interpretations.

“Indebtedness” means, with respect to any Person, (i) all indebtedness of such Person, whether or not contingent, whether secured or unsecured, for borrowed money; (ii) all obligations and liabilities of such Person for the deferred purchase price of property or services; (iii) all indebtedness and obligations of such Person evidenced by

notes, bonds, debentures, finance leases or other similar instruments and liabilities, whether contingent or not contingent, for reimbursement in respect of any letter of credit, banker’s acceptance or similar credit transaction; (iv) all obligations and liabilities in respect of any lease of (or other arrangements conveying the right to use) real or personal property, or a combination thereof, which liabilities are required to be classified and accounted for under GAAP as capital leases; (v) all obligations and liabilities with respect to hedging, swaps or similar arrangements; and (vi) all guarantees, pledges and grants of a security interest by such Person in respect of or securing obligations with respect to the indebtedness of others referred to in clauses (i) through (v) above.

“Indemnified Party” means any of the Seller Indemnified Parties or the Buyer Indemnified Parties who or which may seek indemnification under this Agreement.

“Indemnifying Party” means a party against whom indemnification may be sought under this Agreement.

“Independent Engineer” means GL Garrad Hassan, or if GL Garrad Hassan refuses to be retained for the purposes contemplated by this Agreement, another nationally recognized independent engineer mutually acceptable to Buyer and Seller.

“Intellectual Property” means, collectively, whether registered or not, all U.S. and foreign (i) inventions and discoveries (whether patentable or not and whether or not reduced to practice) and all patents, patentable improvements thereof, patent applications, registrations and invention disclosures therefor, together with all reissues, divisionals, substitutions, continuations, continuations-in-part, extensions, or re-examinations, renewals and reissues thereof, as applicable; (ii) trademarks, service marks, trade names, brand names, certification marks, collective marks, trade dress, assumed names, fictitious names, logos, symbols, slogans, domain names and other indicia or origin, and all goodwill associated or symbolized therewith, together with all applications and registrations in connection therewith; (iii) copyrights and all applications and registrations in connection therewith and renewals of the same; (iv) proprietary or confidential know-how, trade secrets and business information (including proprietary or confidential research and development, know-how, formulas, compositions, manufacturing and production processes and techniques, methods, technical data, designs, drawings, specifications, customer and supplier lists, pricing and cost information and business and marketing plans and proposals); and (v) rights in computer software (including rights in data, databases, and related documentation).

“ITC Grant” means a payment for specified energy property in lieu of tax credits pursuant to Section 1603 of Division B of the American Recovery and Reinvestment Act of 2009, P.L. 111-5.

“ITC Grant Proceeds” means the proceeds of ITC Grants.

“Law” means any federal, state, provincial, foreign or local laws (including common law), constitutions, statutes, codes, rules, treaties, regulations, ordinances, executive orders, decrees or edicts by a Governmental Entity having the force of law.

“Losses” means and includes any and all losses, liabilities, demands, claims, actions, causes of action, costs, obligations, damages, deficiencies, Taxes, penalties, fines or expenses, whether or not arising out of third party claims, including interest, penalties, reasonable attorneys’ fees and expenses, court costs and all amounts paid in investigation, remediation, correcting a condition of noncompliance, defense or settlement of any of the foregoing.

“Material Adverse Effect” means any change, effect, event, circumstance, occurrence, fact, condition or development that, taken together with all other changes, effects, events, circumstances, occurrences, facts, conditions, and developments, (a) is materially adverse to the Business or the assets, liabilities, properties, operations, or financial condition of the Acquired Companies, taken as a whole or (b) would have a material adverse effect on the ability of Seller or Buyer, as the case may be, to consummate the transactions contemplated hereby, other than any change, effect, event, circumstance, occurrence, fact, condition or development relating to or arising out of (i) conditions affecting the national, regional or world economies generally; (ii) conditions affecting the industries or markets in which the Acquired Companies operate; (iii) national or international political or social conditions, including the engagement by the United States in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack upon the United States, or any of its territories, possessions, or diplomatic or consular offices or upon any military installation, equipment or personnel of the United States; (iv) changes in GAAP; (v) changes in Law or other binding directives issued by any Governmental Entity; (vi) the announcement of this Agreement or any other agreements contemplated hereby; (vii) conditions affecting the financial, banking, or securities markets generally; (viii) an act of God to the extent that any such changes, effects, events, circumstances, occurrences, facts, conditions or developments do not cause physical damage or destruction, or render unusable, any facility, property or assets of the Acquired Companies; (ix) any action taken or not taken by Seller or an Acquired Company to the extent expressly required by this Agreement or with the written consent or agreement of, or at the written direction of, Buyer; (x) any action taken, or any omission to act, by Buyer or any of its Affiliates; or (xi) any rulings, orders, findings, motions, filings or other developments in any Actions identified in Section 4.4 of the Seller Disclosure Schedule and related regulatory proceedings; provided, however, that, with respect to the matters included in clauses (i), (ii), (iii), (iv), (v), (vii) and (viii), such matters may constitute or be taken into account in determining whether there has been a Material Adverse Effect to the extent such matters affect the Acquired Companies in a manner that is materially disproportionate to other similarly situated companies operating in the wind electric generating industry.

“Michigan PPAs” means (i) that certain Renewable Energy Purchase Agreement, dated as of June 21, 2010 (as amended, restated, modified, superseded or supplemented from time to time), between Consumers Energy Company and Michigan Wind 2, LLC; (ii) that certain Renewable Energy Purchase Agreement, dated as of June 21, 2010 (as amended, restated, modified, superseded or supplemented from time to time),

between Consumers Energy Company and Harvest II Windfarm, LLC; and (iii) that certain Renewable Energy Purchase Agreement, dated as of June 21, 2010 (as amended, restated, modified, superseded or supplemented from time to time), between Consumers Energy Company and Blissfield Wind Energy, LLC.

“Michigan Wind 2 Project” means the wind project under development in Sanilac County, Michigan, by Michigan Wind 2, LLC, with a nameplate capacity of 90 megawatts.

“Michigan Wind Projects” means, collectively, the Michigan Wind 2 Project, the Harvest II Windfarm Project and the Blissfield Wind Project.

“Michigan Wind Property Agreements” means the Occupancy Agreements pursuant to which each of Michigan Wind 2, LLC, Harvest II Windfarm, LLC and Blissfield Wind Energy, LLC has rights over the real property described therein.

“NERC” means the North American Electric Reliability Corporation or any successor thereto. For the avoidance of doubt, NERC is a Governmental Entity.

“Net Working Capital” means Current Assets minus Current Liabilities.

“Occupancy Agreements” means the leases, subleases, easements, subeasements, use and occupancy or other similar arrangements, together with shared facilities agreements, payment agreements, nondisturbance agreements and subordination agreements, pursuant to which an Acquired Company is a party as a lessee, sublessee or holder of beneficial interest of any easement, subeasement, use and occupancy or other similar arrangements, or party to any ancillary agreement related thereto.

“Order” means any injunction, judgment, order, ruling, assessment, writ or decree of any Governmental Entity.

“Oregon Project Entities” means Oregon Trail Windfarm, LLC, Pacific Canyon Windfarm, LLC, Sand Ranch Windfarm, LLC, Ward Butte Windfarm, LLC, Four Corners Windfarm, LLC, Four Mile Canyon Windfarm, LLC, Big Top, LLC, Butter Creek Power, LLC, Wagon Trail, LLC, and Threemile Canyon Wind I, LLC.

“Partially-Owned Group” means the Persons listed on Section 1.1(e) of the Seller Disclosure Schedule.

“Permitted Encumbrances” means (i) Encumbrances to secure any Seller Intercompany Debt or any Target Company Intercompany Debt of Acquired Companies in the Wholly-Owned Group that, subject to the occurrence of the transactions contemplated hereby to occur on the Closing Date, will be released at or prior to the Closing; (ii) Encumbrances to secure any Third-Party Debt entered into in accordance with Section 6.3 or Target Company Intercompany Debt of Acquired Companies in the Partially-Owned Group; (iii) carriers, warehouseman, mechanics, materialmen and similar Encumbrances which have arisen in the ordinary course of business consistent with past practice and securing obligations that (A) are not yet due or delinquent or (B)

are being contested in good faith and for which reserves have been established on the Financial Statements of the Target Company; (iv) such non-monetary Encumbrances or other imperfections of title, if any, which individually or in the aggregate, are not reasonably likely to impair, in any material respect, the continued use of the asset or property as currently utilized; (v) without limiting in any manner any representation or warranty in Section 4.7 or Section 4.12, Encumbrances imposed or promulgated by Laws with respect to real property and improvements, including zoning, building, subdivision, land use or environmental regulations or other similar requirements or restrictions, other than any monetary Encumbrances unless such monetary Encumbrances (A) are not yet due or delinquent or (B) are being contested in good faith and for which reserves have been established on the Financial Statements of the Target Company; (vi) non-monetary Encumbrances disclosed on the title insurance policies or surveys listed in Section 1.1(f) of the Seller Disclosure Schedule; (vii) Encumbrances for Taxes that (A) are not yet due or delinquent or (B) are being contested in good faith and for which reserves have been established on the Financial Statements of the Target Company; (viii) equipment leases with third parties entered into in the ordinary course of business consistent with past practice and reflected in the Financial Statements of the Target Company; (ix) matters that are the obligations of any Acquired Company under any Occupancy Agreement; (x) restrictions contained in the Material Contracts on the sale, assignment, conveyance or other transfer of any of the Transferred Interests or the membership interests (or other equity interests) in the Acquired Companies; (xi) Encumbrances set forth in Section 1.1(g) of the Seller Disclosure Schedule; and (xii) all matters that a title insurer has insured over or omitted in the title insurance policies listed in Section 1.1(f) of the Seller Disclosure Schedule; provided, that with respect to clauses (v), (vi) (other than matters described in clause (xii) above), (ix), or (xi), excepting any matters which, individually or in the aggregate, are reasonably likely to impair, in any material respect, the continued use of the asset or property as currently utilized by any Acquired Company.

“Person” means an association, a corporation, an individual, a partnership, a limited liability company, an unlimited liability company, a trust, or any other entity or organization, including a Governmental Entity.

“Production Taxes” means any and all (i) state and local taxes determined solely by reference to the amount of electricity produced and without regard to the amount of income or gross receipts derived therefrom; (ii) property taxes or payments in lieu of property taxes, in either case, the amount of which are directly or indirectly determined in whole or in part by the amount of electricity produced by such property; (iii) property taxes; or (iv) taxes, fees, charges or other payments pursuant to (A) a Limitations on Appraised Valuation Agreement under Chapter 313 of the Texas Tax Code or (B) the Oregon Strategic Investment Program established in ORS 285C.600 to 285C.620 and 307.123.

“Prudent Industry Practices” means any of the generally accepted and sound practices, methods and acts engaged in or approved by a significant portion of the wind electric generating industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, could have been expected to accomplish the

desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Industry Practices are not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather are intended to include acceptable practices, methods, or acts generally accepted in the region.

“Release” means any depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, injecting, escaping, dumping, or disposing.

“Representatives” means the directors, officers, members, employees, partners, Affiliates, owners, investors, agents, advisors, counsel, consultants, and representatives of Seller or Buyer or their respective Affiliates, as applicable.

“Seller Confidential Information” means all information of or related to Seller or its Affiliates not related to the Business, including all reports, analyses, notes or other information which contain any such information. Seller Confidential Information shall not include information that (i) is or becomes available to the public other than as a result of a disclosure by Buyer, any Affiliate of Buyer or any of their Representatives in violation of this Agreement; (ii) becomes available to Buyer or any of its Representatives from a source other than Seller or its Representatives, provided that, to Buyer’s Knowledge, the source of such information was not bound by a confidentiality agreement with Seller with respect to such information; or (iii) was or is developed or derived without the aid, application or use of the Seller Confidential Information.

“Seller Disclosure Schedule” means the Schedules delivered by Seller to Buyer on the date hereof.

“Seller Fundamental Representations” means the representations and warranties set forth in Sections 3.1, 3.2, 3.4, 3.5(b), 3.6, 4.1, 4.2, 4.5, 4.8 and 4.21.

“Seller Intercompany Debt” means Indebtedness (other than as it relates to letters of credit or reimbursement obligations for letters of credit) between any Acquired Company and Seller or any of its Affiliates (other than the Acquired Companies).

“Suzlon” means Suzlon Wind Energy Corporation and any successor thereto.

“Target Company Intercompany Debt” means Indebtedness between any Acquired Company and the Target Company or another Acquired Company.

“Target Net Working Capital” means $8,000,000.

“Tax” or “Taxes” means any and all taxes, including any interest, penalties or other additions to tax, that may become payable in respect thereof, imposed by any Governmental Entity, which taxes shall include all income taxes, profits taxes, taxes on gains, alternative minimum taxes, estimated taxes, payroll taxes, employee withholding taxes, unemployment insurance taxes, social security taxes, welfare taxes, disability taxes, severance taxes, license charges, taxes on stock, sales taxes, harmonized sales taxes, use

taxes, ad valorem taxes, value added taxes, excise taxes, goods and services taxes, franchise taxes, gross receipts taxes, gross margin taxes, mortgage recording taxes, occupation taxes, real or personal property taxes, land transfer taxes, stamp taxes, environmental taxes, transfer taxes, workers’ compensation taxes, windfall taxes, net worth taxes, premium taxes, and other taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges of the same or of a similar nature to any of the foregoing. Tax or Taxes also includes abandoned and unclaimed property taxes and escheat taxes and any interest and penalty thereon imposed, assessed or collected by or under the authority of any Governmental Entity.

“Tax Credits” means (i) renewable electricity production credits (as defined in Section 45 of the Code (or any successor to such Section)) that a Person generally is allowed to claim pursuant to Section 38 of the Code (or any successor to such Section) or (ii) any equivalent state Tax credits arising as a result of selling electricity produced by such Person from qualified energy resources at a qualified facility.

“Tax Return” means any and all returns, reports, information returns, forms, declarations, elections, statements, certificates, bills, schedules, claims for refund or other written information of or with respect to any Tax which is supplied to, or required to be filed with or submitted to, any Governmental Entity, including any and all attachments, amendments and supplements thereto.

“Texas Project Entities” means JD Wind 1, LLC; JD Wind 2, LLC; JD Wind 3, LLC; JD Wind 4, LLC; JD Wind 5, LLC; JD Wind 6, LLC; JD Wind 7, LLC; JD Wind 8, LLC; JD Wind 9, LLC; JD Wind 10, LLC, JD Wind 11, LLC, and High Plains Wind Power, LLC.

“Texas PURPA Action” means Civil Action No. A-09-CA-917-SS, JD Wind 1, LLC, et al. v. Smitherman, et al., in the U.S. District Court for the Western District of Texas, Austin Division.

“Texas PURPA Litigation” means the Texas PURPA Action and any related administrative or judicial proceedings for the establishment of legally enforceable obligations for the purchase of electric energy or capacity within the meaning of 18 C.F.R. § 292.304(d)(2) by Southwestern Public Service Company from the Texas Project Entities, which obligations include or relate without limitation to deliveries of electric energy or capacity by the Texas Project Entities occurring prior to the Closing Date.

“Third-Party Debt” means Indebtedness of any Acquired Company owed to any Person other than Seller or its Affiliates (including the Acquired Companies).

“Transferred Employees” means any Designated Employee who accepts an Employment Offer.

“Transfer Taxes” means any and all transfer Taxes (excluding Taxes measured in whole or in part by net income), including sales, use, excise, goods and services, stock, conveyance, gross receipts, registration, business and occupation, securities transactions, real estate, land transfer, stamp, deed, documentary, notarial,

filing, recording, permit, license, authorization and similar Taxes, fees, duties, levies, customs, tariffs, imposts, assessments, obligations and charges.

“Treasury Regulations” means the regulations promulgated under the Code.

“Wholly-Owned Group” means the Persons listed on Section 1.1(h) of the Seller Disclosure Schedule.

ARTICLE II

PURCHASE AND SALE OF INTERESTS

Section 2.1 Purchase and Sale of Transferred Interests.

(a) Buyer and Seller hereby agree that upon the terms and subject to the satisfaction or waiver, if permissible, of the conditions hereof, at the Closing, Buyer shall purchase from Seller, and Seller shall sell, assign, convey, transfer and deliver to Buyer, all of the Transferred Interests free and clear of any and all Encumbrances.

(b) In consideration for the sale, assignment, conveyance, transfer and delivery of all of the Transferred Interests to Buyer, Buyer shall pay to Seller an aggregate amount equal to $860,000,000 (the “Base Purchase Price”), which shall be subject to adjustment in accordance with Section 2.4 and Section 2.5, plus the amounts, if any, to be paid by Buyer to Seller pursuant to Section 2.6. The Base Purchase Price, as adjusted pursuant to Section 2.4, shall be referred to as the “Closing Base Purchase Price,” the Closing Base Purchase Price, as adjusted pursuant to Section 2.5, shall be referred to as the “Final Base Purchase Price,” and the Final Base Purchase Price, as adjusted pursuant to Section 2.6, shall be referred to as the “Total Purchase Price.” A sample calculation of the Closing Base Purchase Price is attached hereto as Attachment 1 to Exhibit 1.

Section 2.2 Payment of Purchase Price. At the Closing, Buyer shall pay to Seller and/or one or more of its Affiliates as may be designated in writing by Seller, by wire transfer in immediately available funds to the account or accounts and in the proportions specified by Seller at least three (3) Business Days prior to Closing, the Closing Base Purchase Price. In furtherance of the foregoing, Seller may direct that a portion of the Closing Base Purchase Price be paid to one or more of its Affiliates in satisfaction of all or a part of the Seller Intercompany Debt.

Section 2.3 Closing.

(a) The closing of the transactions contemplated by Section 2.1 hereof (the “Closing”) shall be held at the offices of Skadden, Arps, Slate, Meagher & Flom LLP, located at Four Times Square, New York, New York, at 10:00 a.m., New York City time, on the third Business Day after the conditions to Closing set forth in Article VII (other than those conditions which are to be satisfied only on the Closing

Date, but subject to the satisfaction or waiver at the Closing of such conditions) have been satisfied and/or waived, or at such other time and date as the parties mutually agree in writing (the “Closing Date”); provided that if the Closing Date were otherwise to occur on the last five (5) days of a month, the Closing Date shall occur on the last Business Day of the month if either party so elects and notifies the other. The Closing and all related actions shall be deemed to have occurred simultaneously and as of 11:59 p.m. New York City time on the Closing Date.

(b) Deliveries by Seller. At the Closing, Seller shall deliver to Buyer:

(i) an assignment agreement transferring all of the Transferred Interests to Buyer, substantially in the form attached hereto as Exhibit 2 (the “Assignment Agreement”), duly executed by Seller;

(ii) the certificate relating to Seller referred to in Section 7.2(a)(iii) hereof;

(iii) written resignations of each director, manager and officer of the Acquired Companies other than any such director, manager or officer who was appointed or elected solely by a Person other than Seller or any of its Affiliates, effective as of the Closing;

(iv) a payoff and lien release letter from Seller or its Affiliates with respect to the payment or forgiveness of the Seller Intercompany Debt;

(v) a certificate of non-foreign status of Seller meeting the requirements of Treasury Regulation Section 1.1445-2(b)(2);

(vi) a transition services agreement, as described in Section 6.9 and substantially in the form attached hereto as Exhibit 3 (the “Transition Services Agreement”), duly executed by Seller;

(vii) an assignment and assumption agreement, in such form and substance reasonably acceptable to Buyer, pursuant to which Seller and its Affiliates (other than the Acquired Companies) assign to Target Company or one or more of the other Acquired Companies, subject to Section 2.7, any and all rights that Seller or such Affiliates may have in any operating wind projects or Development Projects; and

(viii) all other documents required to be delivered by Seller on or prior to the Closing Date pursuant to this Agreement or otherwise required from Seller in connection herewith.

(i) to Seller and/or any of its Affiliates designated by it the Closing Base Purchase Price, pursuant to Section 2.2;

(ii) to Seller the Assignment Agreement, duly executed by Buyer;

(iii) to Seller the certificate referred to in Section 7.3(a)(iii) hereof;

(iv) the Transition Services Agreement, duly executed by Buyer; and

(v) to the applicable Person all other documents required to be delivered by Buyer on or prior to the Closing Date pursuant to this Agreement or otherwise required from Buyer in connection herewith.

Section 2.4 Pre-Closing Purchase Price Adjustment.

(a) At least five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Buyer a statement setting forth the Aggregate Interim Capital Expenditures For Development Projects (the “Capital Expenditure Statement”), together with a certificate of a senior officer of Seller certifying the accuracy of the Capital Expenditure Statement. The Base Purchase Price shall be increased dollar for dollar by the Aggregate Interim Capital Expenditures For Development Projects. All adjustments made pursuant to this Section 2.4 shall, to the maximum extent permitted by applicable Law, be treated by all parties hereto (and all of their Affiliates) for all Tax purposes as adjustments to the Total Purchase Price.

(b) At least five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Buyer an estimate (the “Estimated Net Working Capital Statement”) of the Target Company’s Net Working Capital as of the close of business on the date immediately preceding the Closing Date (the “Estimated Closing Net Working Capital”), together with a reasonably detailed explanation of the calculation thereof and a certificate of a senior officer of Seller stating that the Estimated Net Working Capital Statement reflects the Target Company’s good faith estimates of Net Working Capital as of the close of business on the date immediately preceding the expected Closing Date and was prepared in a manner consistent with the principles set forth in the definitions of Current Assets and Current Liabilities. At the Closing:

(i) if the Estimated Closing Net Working Capital is less than the Target Net Working Capital, the Closing Base Purchase Price shall be reduced by an amount equal to such deficiency; and

(ii) if the Estimated Closing Net Working Capital exceeds the Target Net Working Capital, the Closing Base Purchase Price shall be increased by an amount equal to such excess.

(iii) For the avoidance of doubt, any failure by Buyer to object to the determination of the Estimated Closing Net Working Capital shall not in any way limit Buyer’s rights under Section 2.5, including with respect to items on the Estimated Net Working Capital Statement.

Section 2.5 Post-Closing Purchase Price Adjustment.

(a) As promptly as practicable, but in no event later than ninety (90) days after the Closing Date, Buyer shall in good faith prepare and deliver to Seller (i) a balance sheet of the Target Company as of the close of business on the date immediately preceding the Closing Date (the “Closing Balance Sheet”), (ii) a statement (the “Closing Net Working Capital Statement”) setting forth Buyer’s calculation of the Net Working Capital as of the close of business on the date immediately preceding the Closing Date, based on such Closing Balance Sheet and the principles set forth in the definitions of Current Assets and Current Liabilities (the “Closing Net Working Capital”) along with a reasonably detailed explanation of the calculation thereof, and (iii) a certificate of a senior officer of Buyer stating that the Closing Balance Sheet and the Closing Net Working Capital Statement have been prepared in a manner consistent with the principles set forth in the definitions of Current Assets and Current Liabilities.

(b) Buyer shall permit Seller and its Representatives to have reasonable access during normal business hours to review the books, records and other documents (including work papers) of the Acquired Companies pertaining to or used in connection with preparation of the Closing Balance Sheet and Buyer’s calculation of the Closing Net Working Capital and provide Seller with copies thereof (other than work papers) (as reasonably requested by Seller). If Seller disagrees with Buyer’s calculation of the Closing Net Working Capital as set forth on the Closing Balance Sheet, Seller shall, within forty-five (45) days after Seller’s receipt of the Closing Balance Sheet, notify Buyer in writing of such disagreement by setting forth Seller’s calculation of the Closing Net Working Capital and describing in reasonable detail the basis for such disagreement (an “Objection Notice”). If no Objection Notice is delivered on or prior to the forty-fifth (45th) day after Seller’s receipt of the Closing Balance Sheet, Buyer’s calculation of the Closing Net Working Capital shall be deemed to be binding on the parties hereto. If an Objection Notice is timely delivered to Buyer, then Buyer and Seller shall negotiate in good faith to resolve their disagreements with respect to the computation of the Closing Net Working Capital. In the event that Buyer and Seller are unable to resolve all such disagreements within thirty (30) days after Buyer’s receipt of such Objection Notice, Buyer and Seller shall submit such remaining disagreements to Ernst & Young LLP or if Ernst & Young LLP refuses to be retained for this purpose, another independent, nationally recognized accounting firm, other than Deloitte LLP and PricewaterhouseCoopers, mutually acceptable to Buyer and Seller (Ernst & Young LLP or such mutually acceptable accounting firm, the “Auditor”) for resolution. If Ernst & Young LLP refuses to be retained for this purpose and the parties hereto cannot agree on the selection of an independent, nationally recognized accounting firm to act as the Auditor, either party may request the American Arbitration Association sitting in Chicago, Illinois to appoint a partner at any such accounting firm to act as the Auditor, and such appointment will be conclusive and binding on the parties.

(c) Buyer and Seller shall use their respective reasonable efforts to cause the Auditor to resolve all remaining disagreements with respect to the computation of the Closing Net Working Capital as soon as practicable, but in any event shall direct the Auditor to render a determination within forty-five (45) days after its retention. The Auditor shall consider only those items and amounts in Buyer’s and Seller’s respective calculations of the Closing Net Working Capital that are identified as being items and amounts to which Buyer and Seller have been unable to agree on. In resolving any disputed item, the Auditor shall act as an expert and not as an arbitrator, and the Auditor may not assign a value to any item greater than the greatest value for such item claimed by either party or less than the smallest value for such item claimed by either party. The Auditor’s determination of the Closing Net Working Capital shall be based solely on written materials submitted by Buyer and Seller (and not on independent review) and on the definition of “Net Working Capital” included herein. The determination of the Auditor shall be conclusive and binding upon the parties hereto.

(d) The fees, costs and expenses of the Auditor in determining the Closing Net Working Capital shall be borne by the party which, in the conclusive judgment of the Auditor, is not the prevailing party, or if the Auditor determines that neither Buyer nor Seller could be fairly found to be the prevailing party, then such fees, costs and expenses shall be borne by Buyer and Seller ratably according to the percentage of the amount in dispute awarded to such party.

(e) Within five (5) Business Days after the Closing Net Working Capital is finally determined pursuant to this Section 2.5:

(i) if the Closing Net Working Capital is less than the Estimated Closing Net Working Capital, Seller shall pay to Buyer an amount equal to such deficiency; or

(ii) if the Closing Net Working Capital is greater than the Estimated Closing Net Working Capital, Buyer shall pay to Seller an amount equal to such excess.

(f) Any payments made pursuant to Section 2.5(e) shall be made by wire transfer of immediately available funds to the account designated by Buyer or Seller, as applicable. All payments made pursuant to Section 2.5(e) shall be treated by all parties hereto (and all of their Affiliates) for all Tax purposes as adjustments to the Total Purchase Price to the maximum extent permitted by applicable Law.

(g) Notwithstanding anything in Section 2.4 or Section 2.5 to the contrary, any and all adjustments to the Base Purchase Price and/or the Closing Base Purchase Price made pursuant to Section 2.4 or Section 2.5, as applicable, will be made so as to avoid duplication of any items, and will not include items, to the extent otherwise contemplated, in connection with any other adjustments to the Base Purchase Price and/or the Closing Base Purchase Price made pursuant to this Agreement.

Section 2.6 Michigan Wind Projects Earn Out.

(a) At such time as (i) the Michigan Wind 2 Project achieves Completion of Development and Commencement of Construction, Buyer shall deliver to Seller an amount equal to $16,000,000, (ii) the Harvest II Windfarm Project achieves Completion of Development and Commencement of Construction, Buyer shall deliver to Seller an amount equal to $10,000,000 and (iii) the Blissfield Wind Project achieves Completion of Development and Commencement of Construction, Buyer shall deliver to Seller an amount equal to $14,000,000. Once a particular Michigan Wind Project has achieved Completion of Development and Commencement of Construction, Buyer shall promptly deliver written notice thereof to Seller. Notwithstanding the foregoing, with respect to any Michigan Wind Project that has not achieved Completion of Development and Commencement of Construction, if on or prior to the applicable Commercial Operation Milestone Date (as defined in the applicable Michigan PPA) Buyer or its applicable Affiliate sells, directly or indirectly, such Michigan Wind Project, then (y) for purposes of this Section 2.6, such sale shall be deemed to constitute the Completion of Development and Commencement of Construction of such Michigan Wind Project and (z) the applicable amount set forth in this Section 2.6(a) shall be due and payable by Buyer to Seller in accordance with this Section 2.6.

(b) From and after the Closing, Buyer shall continue the development of the three separate Michigan Wind Projects using all commercially reasonable efforts and Prudent Industry Practices to, among other things, proceed with land acquisition, permitting, turbine purchase and construction agreements and interconnection arrangements, all intending to complete development and commence construction such that the Michigan Wind Projects would commence construction by the applicable Construction Start Milestone Date (as defined in the applicable Michigan PPA) and achieve commercial operation by the applicable Commercial Operation Milestone Date (as defined in the applicable Michigan PPA). Subject to the preceding sentence, the details and manner of such development efforts and the schedule therefor shall be within the sole discretion of Buyer. Buyer shall keep Seller informed on a reasonable, periodic basis, but no less frequently than quarterly, regarding the development of each Michigan Wind Project. In the event Buyer reasonably determines that continuing to proceed with any one or more of the Michigan Wind Projects would not be commercially reasonable and thereafter determines to permanently cease development of and abandon such Michigan Wind
Project(s), Buyer shall so inform Seller, including the reason therefor and thereafter Buyer shall have no further obligation to Seller in connection with such development; provided that if within three (3) years thereafter the Completion of Development and Commencement of Construction of a particular Michigan Wind Project (including, for the avoidance of doubt, the direct or indirect sale of such Michigan Wind Project prior to the Commercial Operation Milestone Date (as defined in the applicable Michigan PPA) to a Person engaged in the Business) occurs, then Buyer shall have the payment obligations set forth in this Section 2.6 with respect to such Michigan Wind Project.

(c) In the event that, prior to Buyer’s delivery of the notice required by Section 2.6(a) with respect to a particular Michigan Wind Project, Seller reasonably believes in good faith that such Michigan Wind Project has achieved Completion of Development and Commencement of Construction, Seller shall promptly

notify Buyer in writing. If Buyer disputes Seller’s reasonable, good faith belief as to whether such Michigan Wind Project has achieved Completion of Development and Commencement of Construction, Buyer shall notify Seller in writing of such dispute within twenty (20) days after Buyer’s receipt of such notice from Seller. If Buyer fails to deliver such notice of dispute within such time period, or otherwise accepts Seller’s reasonable, good faith belief, then such Michigan Wind Project shall be deemed to have achieved Completion of Development and Commencement of Construction. If Buyer does deliver such notice of dispute within such time period, then Buyer and Seller shall, in good faith, attempt to resolve such dispute. If the parties are unable to so resolve such dispute within thirty (30) days, such dispute will be submitted to the Independent Engineer for resolution. The parties shall use their respective reasonable efforts to cause the Independent Engineer to resolve such dispute as soon as practicable, but in any event shall direct the Independent Engineer to render a determination within forty-five (45) days after its retention. The determination of the Independent Engineer shall be conclusive and binding upon the parties. The fees, costs and expenses of the Independent Engineer in resolving such dispute shall be borne by the party which, in the conclusive judgment of the Independent Engineer, is not the prevailing party.

(d) Any amount payable pursuant to this Section 2.6 in respect of a particular Michigan Wind Project shall be paid by Buyer to Seller and/or one or more of its Affiliates as may be designated in writing by Seller, by wire transfer in immediately available funds to the account or accounts and in the proportions specified by Seller to Buyer in writing after the date on which Seller receives the notice from Buyer described in Section 2.6(a) or the date such Michigan Wind Project is determined, in accordance with Section 2.6(c), to have achieved Completion of Development and Commencement of Construction, as the case may be (the “Determination Date”), and Buyer shall make such payment (i) if the Determination Date occurs prior to the Closing Date, on the Closing Date (provided that Buyer has received the applicable wire transfer instructions from Seller in advance of the Closing Date) or (ii) if the Determination Date occurs on or after the Closing Date, within five (5) Business Days after the later of Buyer’s receipt of the applicable wire transfer instructions from Seller or the Determination Date.

(e) Any amount paid by Buyer to Seller pursuant to this Section 2.6 with respect to any of the Michigan Wind Projects shall, to the maximum extent permitted by applicable Law, be treated for all Tax purposes as an amount paid by Buyer to Seller for such Michigan Wind Project, or for an interest in the Acquired Company that owns such Michigan Wind Project, as applicable. Within forty-five (45) days after Seller’s receipt of any payment made by Buyer pursuant to this Section 2.6, Seller shall provide Buyer with an accounting of the payment, for Tax purposes, setting forth the amount of the payment that constitutes interest and the amount of the payment that constitutes principal, computed in accordance with the principles of Section 483 of the Code and the Treasury Regulations promulgated thereunder. To the extent permitted by Law, Buyer and Seller shall (i) timely file with each relevant Governmental Entity all forms and Tax Returns required to be filed in connection with such accounting, (ii) be bound by such accounting for purposes of determining Taxes, (iii) prepare and file, and cause its respective Affiliates to prepare and file, its Tax Returns on a basis consistent with such accounting, and (iv) not take any position, or cause its respective Affiliates to

take any position, inconsistent with such accounting on any Tax Return, in any audit or proceeding before any Governmental Entity or in any report made for Tax purposes; provided, however, that, notwithstanding anything in this Section 2.6(e) to the contrary, the parties shall be permitted to take a position inconsistent with that set forth in the accounting if required to do so by a final and non-appealable decision, judgment, decree or other order by any court of competent jurisdiction.

Section 2.7 Seller Contracts. Nothing in this Agreement (including Section 2.3(b)(vii)) shall constitute an agreement to assign, convey or transfer to the Target Company or one or more of the other Acquired Companies, as the case may be, any Contract of Seller or its Affiliates (other than the Acquired Companies) related to the Business (the “Seller Contracts”), as to which consent or approval is required from any third party but which has not been obtained as of the Closing Date unless and until such consent or approval is no longer required or has been obtained. Seller shall, and shall cause its applicable Affiliates to, use commercially reasonable efforts to secure any such required consent or approval; provided, however, that Seller shall not be required to make any payment in excess of de minimis amounts to obtain any such consent. Notwithstanding the foregoing, if a required consent or approval to the assignment of a Seller Contract is not obtained prior to Closing, then (a) to the extent not addressed in clause (b) below, Seller and Buyer shall enter into a commercially reasonable arrangement at Closing designed to provide the Target Company or one or more of the other Acquired Companies, as the case may be, with all of the benefits of such Seller Contract to the extent not assigned or assumed, and (b) Seller shall, and shall cause its applicable Affiliates to, pursue on behalf of the Target Company or one or more of the other Acquired Companies, as the case may be, any and all claims or rights of Seller or any such Affiliate of Seller under such Seller Contracts and shall use, and cause its applicable Affiliates to use, commercially reasonable efforts to obtain the benefits thereof for the Target Company or one or more of the other Acquired Companies, as the case may be; provided, however, that following the Closing, Seller shall, and shall cause its applicable Affiliates to, continue to use commercially reasonable efforts as described herein to secure any outstanding consents or approvals until such time as Buyer and Seller mutually agree in writing for Seller to abandon such efforts. Notwithstanding anything else set forth in this Section 2.7, neither Buyer nor Seller shall be required to take any action that may, in the reasonable judgment of either Buyer or Seller, (i) result in a violation of any obligation which Seller has to the counterparty to the applicable Seller Contract, provided that Seller shall use commercially reasonable efforts to cause such obligation to be waived or terminated with respect to the transactions provided for in this Agreement, or (ii) otherwise violate applicable Law. For the avoidance of doubt, as between Seller and Buyer, all Seller Contracts shall be deemed, to the maximum extent permitted by Law, to have been sold by Seller and assumed by Buyer at the Closing.

ARTICLE III

REPRESENTATIONS AND WARRANTIES REGARDING SELLER

Seller hereby represents and warrants to Buyer as follows:

Section 3.1 Due Organization and Good Standing. Seller is a corporation duly incorporated, validly existing and in good standing under the laws of the State of Delaware. Seller has previously made available to Buyer complete and correct copies of the certificate of incorporation and by-laws of Seller, as amended to the date hereof, and such certificate of incorporation and by-laws, as so made available to Buyer, are in full force and effect, and Seller is not in violation of its certificate of incorporation or by-laws, except in each case as would not, or would not be reasonably expected to, individually or in the aggregate, impair in any material respect Seller’s ability to perform its obligations under this Agreement or to consummate the transactions contemplated hereby.

Section 3.2 Authorization of Transaction. Seller has full power and authority to execute and deliver this Agreement, to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby have been duly and validly authorized by all required corporate or other action on the part of Seller and no other corporate or other proceedings on the part of Seller are necessary to authorize the execution, delivery and performance of this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly executed and delivered by Seller and constitutes (assuming the due execution and delivery by Buyer) a valid and legally binding obligation of Seller, enforceable in accordance with its terms, except as such enforcement may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar Laws relating to or affecting the rights and remedies of creditors generally and subject to general principles of equity (whether considered in a proceeding at law or in equity).

Section 3.3 Approvals. No filing or registration with, notification to, or authorization, consent, approval or waiver of any Governmental Entity is required or otherwise necessary for the execution, delivery and performance of this Agreement by Seller or the consummation by Seller of the transactions contemplated hereby, except (a) as set forth in Section 3.3 of the Seller Disclosure Schedule, (b) filings under the HSR Act, (c) filings that become applicable as a result of matters specifically related to Buyer or its Affiliates or (d) filings with and approvals from FERC (such Governmental Entity filings, registrations, notifications, authorizations, consents or approvals set forth in clauses (a) through (d) above being hereinafter referred to collectively as the “Seller Required Approvals”) or (e) such other Governmental Entity filings, registrations, notifications, authorizations, consents or approvals the failure of which to be obtained or made would not, or would not be reasonably expected to, individually or in the aggregate, (i) be material to (A) the Acquired Companies taken as a whole, (B) the operation of any material portion of the Business or (C) the operation of the Business taken as a whole or (ii) impair in any material respect Seller’s ability to perform its obligations under this Agreement or to consummate the transactions contemplated hereby.

Section 3.4 Ownership of the Transferred Interests. Seller is the sole beneficial and record owner of, and has good and valid title to, all of the Transferred Interests, free and clear of all Encumbrances. Upon delivery of the Transferred Interests at the Closing as provided in Section 2.1, Buyer will acquire good and valid title to the Transferred Interests, free and clear of all Encumbrances. Except for the Transferred Interests, there are no other issued and outstanding membership interests (or other equity interests or securities) of the Target Company, and the sale and delivery of the Transferred Interests as contemplated by this Agreement are not subject to any preemptive rights, rights of first refusal or other similar rights or restrictions.

Section 3.5 No Conflict or Violation. The execution, delivery and performance of this Agreement by Seller and the consummation of the transactions contemplated hereby will not, assuming all Seller Required Approvals and the consents described in Section 3.5 of the Seller Disclosure Schedule have been obtained, (a) violate any applicable Law or Order applicable to Seller or any Acquired Company, (b) conflict with, result in or give rise to any breach or violation of, a termination (or a right of termination) or a default (with or without notice or lapse of time or both) under (any such conflict, violation, termination or default, a “Violation”) the Charter Documents of Seller, (c) constitute or result in a Violation or amendment, cancellation, suspension or acceleration under, or resulting in a loss of any benefit or requiring any notification to any counterparty under, any Material Contract to which Seller or any Acquired Company is a party or by which any of them or any of their respective properties or assets may be bound or affected, or (d) result in the creation of any Encumbrance (other than any immaterial Encumbrances) upon the properties or assets of any of the Acquired Companies, except in the case of clauses (a) and (c), as would not, or would not be reasonably expected to, individually or in the aggregate, (i) be material to (A) the Acquired Companies taken as a whole, (B) the operation of any material portion of the Business or (C) the operation of the Business taken as a whole, (ii) impair in any material respect the ability of Seller to perform its obligations hereunder or (iii) prevent or materially delay consummation of the transactions contemplated hereby.

Section 3.6 Brokers’ Fees. Neither Seller nor any of its Affiliates or its or their directors (or Persons in similar positions), officers, employees or agents has employed any broker or finder or incurred any liability for any investment banking fees, brokerage fees, commissions or finders’ fees in connection with the transactions contemplated by this Agreement for which Buyer or, in the event the Closing occurs, any of the Acquired Companies would have any liability or otherwise be liable.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

REGARDING THE ACQUIRED COMPANIES

Seller hereby represents and warrants to Buyer as follows:

Section 4.1 Due Organization and Good Standing. The Acquired Companies are each duly organized, validly existing and, to the extent such concept is recognized, in good standing under the laws of the state of their organization, as set forth opposite such Acquired Company’s name on Section 4.1 of the Seller Disclosure Schedule. Each Acquired Company has all requisite corporate or similar power and authority necessary to own, lease or operate all of its properties and assets and to carry on its business as it is being conducted as of the date hereof, and is duly licensed or qualified to do business and, if applicable, is in good standing in each jurisdiction in which the nature of the business conducted by it or the character or location of the properties and assets owned or leased or held under license by it makes such licensing or qualification necessary, except where the failure to be so licensed, qualified or in good standing would not, or would not be reasonably expected to, individually or in the aggregate, be material to (a) the Acquired Companies taken as a whole, (b) the operation of any material portion of the Business or (c) the operation of the Business taken as a whole, or prevent or materially delay consummation of the transactions contemplated by this Agreement.

Section 4.2 Capital Structure.

(a) Section 4.2(a)(i) of the Seller Disclosure Schedule sets forth the authorized and outstanding membership interests (or other equity interests or securities) of each of the Acquired Companies and the beneficial and record owners of such outstanding membership interests (or other equity interests or securities). The Target Company or one or more of the other Acquired Companies is the sole beneficial and record owner of, and has good and valid title to, all of the issued and outstanding membership interests (or other ownership interests) of the Acquired Companies other than such membership interests (or other ownership interests) of the Partially-Owned Group that are owned by a Person other than the Target Company or one or more of the Acquired Companies. Other than the membership interests (or other equity interests or securities) shown in Section 4.2(a)(i) of the Seller Disclosure Schedule as owned by the Target Company, the Target Company does not own, directly or indirectly, any capital stock, membership interests, partnership interests or other equity or ownership interests in any Person. All of the issued and outstanding membership interests (or other equity interests or securities) of the Acquired Companies that are owned directly or indirectly by Seller or any of its Affiliates are duly authorized, have been validly issued, are fully paid and nonassessable (to the extent applicable), and are free and clear of any and all Encumbrances (other than those Encumbrances set forth in Section 4.2(a)(ii) of the Seller Disclosure Schedule and the Encumbrances described in clauses (i) and (ii) of the definition of “Permitted Encumbrances”).

(b) Except as set forth in Section 4.2(b) of the Seller Disclosure Schedule, there are no agreements, options, warrants, purchase rights, convertible or exchangeable securities, rights of first refusal, preemptive rights, subscriptions or any other rights or arrangements existing or outstanding with respect to the membership interests (or other equity interests or securities) of the Acquired Companies under any provision of applicable Law, the Charter Documents of Seller or any of the Acquired Companies, or any Contract (other than this Agreement) to which Seller or any of the Acquired Companies is a party or otherwise bound. There are no issued or outstanding bonds, debentures, notes, obligations or other Indebtedness of any of the Acquired Companies the holders of which have the right to vote on any matters upon which the member or owners of any such Acquired Company may vote.

(c) Except as set forth in Section 4.2(c) of the Seller Disclosure Schedule, there are no, and neither Seller nor any of the Acquired Companies is party to, bound by or subject to any, stockholder agreements, voting trusts, proxies or other agreements or understandings relating to the holding, voting, sale, purchase, redemption or other acquisition of the membership interests (or other equity interests or securities) of the Acquired Companies; or agreements, commitments, arrangements, understandings or other obligations to declare, make or pay any dividends or distributions, whether current or accumulated, or due or payable, on any securities of the Acquired Companies.

(d) There are no wind energy or biomass projects under active development by (i) the Target Company, (ii) any of the Development Companies or (iii) Seller or any of its other Affiliates as of the date of this Agreement, other than those described in Section 1.1(c) of the Seller Disclosure Schedule and those activities described in the last sentence of Section 6.2(d).

Section 4.3 Financial Statements; No Undisclosed Liabilities.

(a) Set forth in Section 4.3(a) of the Seller Disclosure Schedule are true and complete copies of the audited consolidated balance sheet and statements of income and cash flows for the fiscal year ended October 31, 2009 (the “2009 Financial Statements”) and the unaudited consolidated balance sheets and statements of income and cash flows for the nine (9) months ended July 31, 2010 (the “2010 Financial Statements,” and together with the 2009 Financial Statements, the “Financial Statements”) of the Target Company. Except as otherwise indicated in the Financial Statements, and subject to the absence of footnote disclosure and normal year-end adjustments in the 2010 Financial Statements, the Financial Statements were prepared in accordance with GAAP, applied on a consistent basis, and consistent with past practice as at the date and for and during the periods involved, and fairly present, in all material respects, the financial condition of the Target Company as of October 31, 2009 and July 31, 2010, as applicable, and the results of its operations and cash flows for the periods then ended. The Financial Statements have been prepared from the Books and Records of the Target Company. Except for the Seller Intercompany Debt, there are no assets, properties or liabilities of any Acquired Company recorded on any financial statements of Seller or any of its Affiliates (other than the Target Company) that are not reflected on the Financial Statements.

(b) Except (i) as and to the extent set forth in the Financial Statements, (ii) for liabilities permitted by or incurred pursuant to this Agreement, and (iii) for liabilities incurred in the ordinary course of business consistent with past practice since July 31, 2010, none of the Acquired Companies has directly or indirectly, since July 31, 2010, incurred any liabilities that would be required by GAAP (consistently applied in accordance with past practice) to be reflected on a balance sheet of the Target Company, which, individually or in the aggregate, are material and are not of the same character and nature as the liabilities set forth in the balance sheet included in the 2010 Financial Statements.

Section 4.4 Legal Proceedings. Except as set forth in Section 4.4 of the Seller Disclosure Schedule:

(a) As of the date hereof, there are no Actions pending, or, to Seller’s Knowledge, threatened against Seller or any of the Acquired Companies (or any of their respective officers or directors in connection with the Business), which, if adversely determined, would, or would be reasonably expected to, individually or in the aggregate, be material to (i) the Acquired Companies taken as a whole, (ii) the operation of any material portion of the Business or (iii) the operation of the Business taken as a whole, or impair in any material respect the ability of Seller to perform its obligations hereunder.

(b) As of the date hereof, there are no such Actions pending or, to Seller’s Knowledge, threatened challenging the validity or propriety of, or seeking to prevent, enjoin or materially delay consummation of, the transactions contemplated hereby.

(c) Neither Seller nor any of the Acquired Companies is subject to any Order which would, or would be reasonably expected to, individually or in the aggregate, be material to (i) the Acquired Companies taken as a whole, (ii) the operation of any material portion of the Business or (iii) the operation of the Business taken as a whole, or impair in any material respect the ability of Seller to perform its obligations hereunder.

Section 4.5 Taxes. Except as set forth in Section 4.5 of the Seller Disclosure Schedule:

(a) Each Acquired Company comprising the Wholly-Owned Group is classified as and is treated as disregarded as an entity separate from its owner for U.S. federal and state income Tax purposes.

(b) Each Acquired Company comprising the Partially-Owned Group is classified as and is treated as a partnership for U.S. federal and state income Tax purposes, and Seller is and is treated as a partner in each Acquired Company comprising the Partially-Owned Group for U.S. federal and state income Tax purposes.

(c) Seller is the common parent of the “affiliated group” within the meaning of Section 1504 of the Code that includes the income, assets or operations of the Acquired Companies.

(d) All material Tax Returns required to be filed by any Acquired Company, or by Seller, with respect to the income, assets or operations of any Acquired Company, have been timely filed, and all such Tax Returns were true, correct and complete in all material respects.

(e) All material Taxes required to be paid by any Acquired Company, or by Seller, with respect to the income, assets or operations of any Acquired Company, have been timely paid.

(f) All material Taxes of the Acquired Companies not yet due and payable for a Tax period ending on or before the date of the 2010 Financial Statements have been adequately accrued and provided for in accordance with GAAP on the 2010 Financial Statements.

(g) Neither Seller nor any Acquired Company has extended or waived the application of any statute of limitations of any jurisdiction regarding the assessment or collection of any material Tax of or with respect to the income, assets or operations of any Acquired Company.

(h) There are no audits, claims, disputes, investigations or assessments regarding material Taxes pending against any Acquired Company, or against Seller, with respect to the income, assets or operations of any Acquired Company, as of the date hereof.

(i) No written claim or other communication has been received by an Acquired Company, or by Seller with respect to an Acquired Company, from a Governmental Entity in any jurisdiction where such Acquired Company does not file Tax Returns stating that the Acquired Company is or may be subject to taxation by that jurisdiction.

(j) Each Acquired Company has withheld, timely paid and reported all material Taxes required to have been withheld, paid and reported by such Acquired Company in connection with amounts paid or owing to any employee, creditor, stockholder, member, licensor or independent contractor.

(k) There are no Encumbrances for Taxes with respect to the assets of any Acquired Company other than Encumbrances for Taxes (i) that are not yet due or delinquent, (ii) that are being contested in good faith, or (iii) for which reserves have been, or would be required to be, established on the financial statements of the Target Company in accordance with GAAP.

(l) None of the Acquired Companies is a party to or bound by any material Tax sharing, Tax allocation, Tax indemnity or similar agreement or arrangement, that may obligate an Acquired Company to make a material payment

related to Taxes to a third party, except for certain agreements or arrangements providing for the allocation or payment of: real property Taxes; Production Taxes; personal property Taxes; sales Taxes; use Taxes; value added Taxes; or other similar Taxes with respect to real or personal property leased by any Acquired Company.

(m) No Acquired Company will be required to include in a Tax period beginning after the Closing Date taxable income attributable to income that accrued in a prior Tax period but was not recognized in any prior Tax period as a result of (i) any closing agreement entered into prior to the Closing Date pursuant to Section 7121 of the Code (or any similar provision of state, local or non-U.S. income Tax Law), (ii) any “installment sale,” within the meaning of Section 453 of the Code (or any similar provision of state, local or non-U.S. income Tax Law), that occurred prior to the Closing Date, or (iii) any adjustments required pursuant to Section 481 of the Code (or any similar provision of state, local or non-U.S. income Tax Law) as a result of any changes in accounting methods that occurred prior to the Closing Date.

(n) With respect to any wind-powered electricity generating facility owned by any Acquired Company (other than any such facility in respect of which ITC Grant Proceeds have been received), (i) no grants have been provided by the United States, a state or a political subdivision of a state for use in connection with such facility, (ii) no proceeds of an issue of state or local government obligations, the interest on which is exempt from U.S. federal income tax under Section 103 of the Code, have been used to provide financing for such facility, (iii) no “subsidized energy financing,” within the meaning of Section 45(b)(3)(A)(iii) of the Code, has been provided under a federal, state or local program in connection with such facility, and (iv) no credits, within the meaning of Section 45(b)(3)(A)(iv) of the Code, have been allowable with respect to such facility.

(o) Since July 31, 2010, except as consistent with past practice, the Acquired Companies have not, and Seller has not with respect to the income, assets or operations of the Acquired Companies, (i) made any changes in reporting for Taxes or Tax accounting methods, (ii) made or rescinded any material Tax election, (iii) filed any material amended Tax Return or claim for refund of material Taxes, (iv) settled or compromised any Tax liability or refund claims other than any such liability or claims that is de minimis, or (v) incurred any material liability for Taxes other than in the ordinary course of business.

(p) The wind-powered electricity generating facilities that are used in the Business of the Acquired Companies meet the requirements of producing electricity from a “qualified energy resource” within the meaning of Section 45 of the Code.

(q) Section 4.5 contains the sole and exclusive representations and warranties provided in Article III and this Article IV with respect to all matters relating to Taxes of or with respect to each Acquired Company and the income, assets and operations of each Acquired Company.

Section 4.6 Acquired Companies’ Contracts.

(a) Set forth in Section 4.6(a) of the Seller Disclosure Schedule is a list of the following Contracts to which any of the Acquired Companies is a party, benefits from or is bound by (other than the Contracts set forth in Sections 4.8(a), 4.11(b)(i), 4.11(c)(i) and 4.21 of the Seller Disclosure Schedule) which have not expired prior to the date hereof in accordance with their respective terms (together with the Suzlon Agreements, Occupancy Agreements and the Michigan Wind Property Agreements, the “Material Contracts”):

(i) each Contract (other than purchase orders and similar agreements entered into in the ordinary course of business consistent with past practice and other than those agreements identified in Section 4.6(a)(x) below) for the purchase of any materials, supplies or services that requires an annual expenditure by any Acquired Company of more than $150,000;

(ii) each Contract that is reasonably anticipated to provide for annual payments to any Acquired Company of more than $150,000;

(iii) each Contract that contains a non-competition, non-interference, non-solicitation or similar covenant or provision which restricts, in any material respect, the ability of any Acquired Company to conduct the Business;

(iv) Contracts entered into within the last three (3) years for the acquisition or disposition of the membership or other equity interests of a former or existing subsidiary of the Target Company or of all or substantially all of the assets of a former or existing subsidiary of the Target Company, other than Contracts under which no party to such Contract has any continuing material rights or obligations;

(v) each employment and consulting Contract providing for payments thereunder in excess of $150,000 per year;

(vi) any loan agreements, credit agreements, security agreements, promissory notes, mortgages, indentures and other Contracts which provide for or relate to (A) the incurrence of Indebtedness by an Acquired Company owed to any other Person (other than an Acquired Company), (B) the guarantee by or letters of credit posted by Seller or any of its Affiliates (other than any Acquired Company, unless an entity other than an Acquired Company is ultimately responsible therefor) with respect to Indebtedness or other obligations of any Acquired Company, (C) the extension of Indebtedness by any Acquired Company to any other Person (other than any Acquired Company) or (D) the guarantee by any Acquired Company of Indebtedness or other obligations of any Person (other than any Acquired Company);

(vii) physical or financial electricity hedge contracts, currency or interest rate hedge contracts, exchange-traded futures or options transactions, over-the-counter transactions or derivatives thereof, interest rate swap agreements or similar transactions;

(viii) the Charter Documents;

(ix) investment agreements or other Contracts for the purchase of membership interests (or other equity interest or securities) of the Acquired Companies or that grant any right of first refusal or right of first offer or similar right or that limits or purports to limit the ability of any Acquired Company to own, operate, sell, transfer, pledge or otherwise dispose of any material amount of its assets or its business;

(x) (A) power purchase or sale agreements (including sales of capacity, energy and ancillary services), (B) renewable energy credit purchase and sale agreements, (C) interconnection agreements, (D) wind turbine purchase agreements (including master agreements and purchase orders related to such master agreements), (E) balance of plant agreements, (F) management agreements, (G) administrative services agreements, (H) warranty agreements, (I) operation, maintenance and service agreements, and (J) transmission agreements;

(xi) any Contract that provides for annual payments in excess of $150,000 to or from any of the Acquired Companies and which primarily relate to (A) the granting to any of the Acquired Companies of license rights in or to any material Intellectual Property owned by a third party, including software, or (B) the granting by any of the Acquired Companies of license rights to a third party in or to any material Intellectual Property, in each of clauses (A) and (B) above, excluding “click-wrap” or “shrink-wrap” agreements, agreements contained in or pertaining to “off-the-shelf” software, or the terms of use or service for any web site;

(xii) any Contract relating to any of the Acquired Companies’ ownership in, or the governance or funding of, any other Person or any liabilities (contingent or otherwise) any of the Acquired Companies has with respect thereto;

(xiii) any Contract with a Governmental Entity;

(xiv) any Contract that (A) limits or contains restrictions on the ability of any Acquired Company to declare or pay dividends on, to make any other distribution in respect of, or to issue or purchase, redeem or otherwise acquire its capital stock, to incur Indebtedness, or to incur or suffer to exist any Encumbrances or (B) requires any Acquired Company to maintain financial ratios or levels of net worth or other indicia of financial condition;

(xv) any Contract containing a change of control provision, termination right or material fee, or any other material restriction or penalty, that would be triggered by a change in ownership or control of the Acquired Companies;

(xvi) any Contract that contains a “most favored nation” clause or requires any type of exclusive dealing or similar arrangement involving any Acquired Company for goods or services that are material to (A) the Acquired Companies taken as a whole, (B) the operation of any material portion of the Business or (C) the operation of the Business taken as a whole; and

(xvii) each other Contract to which any Acquired Company is a party or by which it or its properties are bound that has a term of more than one year and requires annual payments by any Acquired Company of more than $150,000.

(b) As of the date hereof, none of the Acquired Companies has received from the applicable counterparty any written or, to Seller’s Knowledge, oral notice of termination of, or intent to terminate, any Material Contract. Each Material Contract is valid and binding on the Acquired Company which is party thereto and, to Seller’s Knowledge, each other party thereto, and is in full force and effect and enforceable in accordance with its terms (subject to general principles of equity, whether considered in a proceeding at Law or in equity). The applicable Acquired Companies have performed in all material respects all obligations required to be performed by them under each Material Contract and, to Seller’s Knowledge, each other party to each Material Contract has performed in all material respects all obligations required to be performed by it under such Material Contract and has not violated any material provision of such Material Contract or committed any act which (with or without notice, lapse of time or both) would constitute a material default under any provisions of such Material Contract, other than any defaults that have been cured or waived in writing. As of the date hereof, none of the Acquired Companies has received any written or, to Seller’s Knowledge, oral notice from any other party to any of the Material Contracts described in Section 4.6(a)(x) that such other party is entitled to reduce in a material manner any amount to be paid by such party under such Material Contract as a result of or in connection with any action taken or Order issued by any Governmental Entity. Seller has made available to Buyer true and complete copies of all Material Contracts, together with all material amendments, waivers or other changes thereto.

(c) Section 4.6(c) of the Seller Disclosure Schedule lists each Material Contract to which Seller or any of its Affiliates (other than the Acquired Companies) is a party, and as of the date hereof, Seller or such Affiliate of Seller has not assigned each such Material Contract to an Acquired Company.

(d) As of the date hereof, and except as set forth in Section 4.6(d) of the Seller Disclosure Schedule, none of the Acquired Companies has a material outstanding claim or cause of action (including relating to availability), whether for liquidated damages or other monetary damages or otherwise, under any Material Contract (including a warranty agreement), and none of the Acquired Companies has received notice of any claim or cause of action (including relating to availability) against it, whether for liquidated damages or other monetary damages, under any Material Contract (including a power purchase or sale agreement).

(e) As of the date hereof, to Seller’s Knowledge, there are no pending appeals of the Michigan Public Service Commission’s order, dated July 27, 2010, approving the Michigan PPAs.

Section 4.7 Compliance With Law. Except as set forth in Section 4.7 of the Seller Disclosure Schedule, the Acquired Companies are and since January 1, 2007 have been, and are and since January 1, 2007 have been, operating the Business in material compliance with all applicable Laws and Orders. All approvals, permits, licenses, franchises, registrations and variances of or obtained from Governmental Entities (collectively, “Permits”) required to conduct the Business in compliance with all applicable Laws and Orders are in the possession of the Acquired Companies, are in full force and effect and are being complied with, except for such Permits the failure of which to possess or be in compliance with would not, or would not be reasonably expected to, individually or in the aggregate, be material to (a) the Acquired Companies taken as a whole, (b) the operation of any material portion of the Business or (c) the operation of the Business taken as a whole. Seller has made available to Buyer true and complete copies of all such Permits, except for such Permits the failure of which to possess or be in compliance with would not, or would not be reasonably expected to, individually or in the aggregate, be material to (x) the Acquired Companies taken as a whole, (y) the operation of any material portion of the Business or (z) the operation of the Business taken as a whole.

Section 4.8 Employees and Employee Benefit Plans.

(a) Section 4.8(a) of the Seller Disclosure Schedule contains a true and complete list of each material Employee Benefit Plan and identifies the party that maintains or sponsors each such plan. With respect to each Employee Benefit Plan that is subject to ERISA, Seller has made available complete copies of each of the following documents: (i) the formal plan document (including all amendments thereto); (ii) the annual report and actuarial report, if required under ERISA or the Code, for the most recent plan year ending prior to the date hereof; (iii) the most recent “summary plan description” (within the meaning of Section 102 of ERISA), if required under ERISA or the Code; (iv) if the Employee Benefit Plan is funded through a trust or any third party funding vehicle, the trust or other funding agreement; and (v) the most recent determination letter received from the Internal Revenue Service with respect to each Employee Benefit Plan that is intended to be qualified under Section 401(a) of the Code. No Acquired Company maintains or is a sponsor of any Employee Benefit Plan.

(b) No liability under Title IV of ERISA has been incurred by the Acquired Companies that has not been satisfied in full when due, and no condition exists that could reasonably be expected to result in the Acquired Companies incurring any liability under such Title, whether actual or contingent, other than liability for premiums due to the Pension Benefit Guaranty Corporation (which premiums have been paid when due), or incurring any liability under the penalty, excise tax or joint and

several liability provisions of Sections 406, 409, 502(i), 502(l), 4069 or 4212(c) of ERISA or Sections 4971, 4975 or 4976 of the Code. None of the Acquired Companies has, at any time during the six-year period preceding the date of this Agreement, sponsored any Employee Benefit Plan subject to Title I or IV of ERISA or contributed to any multiemployer plan under Section 3(37) of ERISA.

(c) Each Employee Benefit Plan intended to be “qualified” within the meaning of Section 401(a) of the Code has received a favorable determination letter from the Internal Revenue Service as to its qualification and, to Seller’s Knowledge, no event has occurred that could reasonably be expected to result in disqualification of such Employee Benefit Plan.

(d) Each of the Employee Benefit Plans has been operated and administered in accordance with its terms and all applicable Laws, including ERISA and the Code, except where the failure to do so would not result in a material liability to or impairment of (i) the Acquired Companies taken as a whole, (ii) the operation of any material portion of the Business or (iii) the operation of the Business taken as a whole.

(e) Except for obligations that are the sole responsibility and liability of Seller and its Affiliates (other than the Acquired Companies), neither Seller nor any of its Affiliates (including the Acquired Companies) has any obligation to provide any post-employment health, life or other welfare benefits to current or former Business Employees (or dependents or beneficiaries thereof).

(f) Except for severance and retention payments that are the sole responsibility and liability of Seller and its Affiliates (other than the Acquired Companies) in accordance with Section 6.8(c), the consummation of the transactions contemplated hereby will not (i) entitle any current or former Company Employee or any director of the Acquired Companies to severance pay, unemployment compensation or any other payment or (ii) accelerate the time of payment or vesting, or increase the amount of compensation or benefits accrued or payable to any such Company Employee or director. The consummation of the transactions contemplated hereby will not result in any liability to, or encumbrance on the assets, of the Acquired Companies (whether actual or contingent) under Title IV of ERISA.

(g) Section 4.8(g) of the Seller Disclosure Schedule contains a true and complete list of (i) all Business Employees as of August 1, 2010 and (ii) the entity that employs each of them. With respect to the Business Employees, there are no Actions pending or, to the Seller’s Knowledge, threatened in connection with their employment, other than routine claims for benefits. Except as disclosed in Section 4.8(g) of the Seller Disclosure Schedule, none of the Seller, the Acquired Companies or any of their Affiliates maintains any plan, program or is a party to any arrangement that provides any benefits or payments to Business Employees based on, or measured by, the value of any equity security of, or interest in, the Seller, any Acquired Company or any of their Affiliates, and no Business Employee has entered into or is subject to any employment contract with respect to such employment. Seller has provided Buyer a true and complete list of the base salary and target incentive pay as currently in effect for each Company Employee that is a Designated Employee.

(h) None of the Acquired Companies is a party to any Contract that would require it to make any payment that would constitute an “excess parachute payment” for purposes of Sections 280G and 4999 of the Code.

Section 4.9 Labor. The Acquired Companies are not party to any collective bargaining agreement, and none of the Business Employees is represented by any labor union in connection with such employment. There are no pending or, to Seller’s Knowledge, threatened organizing activities or demands or organized work stoppages, labor disputes, strikes or lockouts in respect of the Business Employees.

Section 4.10 Personal Property; Sufficiency of Assets. Except as may be reflected in the Financial Statements or in Section 4.10 of the Seller Disclosure Schedule, (a) the Acquired Companies have good and marketable title free and clear of any Encumbrances, except for Permitted Encumbrances, to all of the personal property, tangible and intangible reflected in the Financial Statements and all personal property acquired since such date, except where the lack of good and marketable title would not, or would not be reasonably expected to, individually or in the aggregate, impair in any material respect the ability of the Acquired Companies to conduct their collective operations or otherwise operate a material portion of the Business; (b) the Acquired Companies own, lease or license all equipment, facilities, and other tangible assets and all intangible assets necessary for the Acquired Companies to conduct the Business substantially in the manner conducted during the twelve (12) month period prior to the date hereof and as currently conducted; and (c) such equipment, facilities, and other tangible assets and all intangible assets are usable in the ordinary course of business consistent with past practice, in good condition and repair in all material respects, except for ordinary wear and tear, and reasonably adequate and suitable for their current uses; provided, that, for the avoidance of doubt, none of the foregoing shall be deemed to constitute a representation or warranty with respect to infringement or other violation of Intellectual Property of a third party, which is addressed in Section 4.13(c).

Section 4.11 Real Property.

(a) Owned Real Property. Section 4.11(a) of the Seller Disclosure Schedule sets forth as of the date hereof a complete and correct list of all real property owned by the Acquired Companies (the “Owned Real Property”). The Acquired Companies have good, valid and marketable fee ownership title to the Owned Real Property, free and clear of all Encumbrances, except for Permitted Encumbrances. No portion of the Owned Real Property is leased or licensed to, or occupied by, any Person other than the Acquired Companies. To Seller’s Knowledge, no portion of the Owned Real Property or real property subject to the Occupancy Agreements (the “Occupied Real Property”) is subject to any pending condemnation proceeding or other proceeding by any public or quasi-public authority, or threatened condemnation or other proceeding with respect to the Owned Real Property.

(b) Occupied Real Property.

(i) Section 4.11(b)(i) of the Seller Disclosure Schedule sets forth a complete list of the Occupancy Agreements. True and complete copies of all Occupancy Agreements, and all modifications, extensions, amendments and assignments thereof, have heretofore been made available to Buyer or its agents.

(ii) The Acquired Companies are not party to any lease, sublease, easement, subeasement, license, concession agreement, use and occupancy agreement, or similar arrangement with respect to real property under which any of the Acquired Companies is a lessor, sublessor, grantor of an easement, subeasement or other interest, licensor or concessionor.

(iii) The Acquired Companies have good, valid and insurable leasehold or easement interests to the real property encumbered by the Occupancy Agreements (and with respect to the Development Projects, to Seller’s Knowledge), free and clear of all Encumbrances on or senior to such leasehold or easement interests, except for Permitted Encumbrances.

(iv) Except with respect to the Development Projects, the Owned Real Property and the interests granted under the Occupancy Agreements are all of the real property interests necessary to conduct the Business of each Acquired Company as currently conducted, and to develop, construct, own, operate, maintain and use all material equipment, facilities and other tangible assets, including the wind turbines, currently owned or operated by each Acquired Company.

(i) Section 4.11(c)(i) of the Seller Disclosure Schedule sets forth a complete list of the Michigan Wind Property Agreements.

(ii) Except as set forth in Section 4.11(c)(ii) of the Seller Disclosure Schedule, to Seller’s Knowledge, the real property interests under the Michigan Wind Property Agreements (other than those to which Blissfield Wind Energy, LLC is a party) are all of the real property interests necessary to develop, construct, own, operate, maintain and use each of the Michigan Wind 2 Project and the Harvest II Windfarm Project, subject to the duration of such real property interests. With respect to those real property interests set forth in Section 4.11(c)(ii) of the Seller Disclosure Schedule, to Seller’s Knowledge, no material impediment exists to obtaining such real property interests in the ordinary course of business consistent with past practice.

(iii) Blissfield Wind Energy, LLC is targeting the acquisition of real property interests in the parcels identified on the map set forth in Section 4.11(c)(iii) of the Seller Disclosure Schedule and real property interests necessary to connect the Blissfield Wind Project into the grid, which, if acquired,

and together with the real property interests already held by the Acquired Companies with respect to the Blissfield Wind Project as set forth in Section 4.1(c)(i) of the Seller Disclosure Schedule, would, in Seller’s reasonable, good faith judgment, constitute all of the real property interests necessary to develop, construct, own, operate, maintain and use the Blissfield Wind Project, subject to the duration of such real property interests. As of the date hereof, to Seller’s Knowledge, no material impediment exists to obtaining the real property interests in the parcels identified on the map set forth in Section 4.11(c)(iii) of the Seller Disclosure Schedule and real property interests necessary to connect the Blissfield Wind Project into the grid, although negotiations with the owners of such real property interests still need to occur.

(iv) Seller is continuing to obtain the Permits necessary to develop, construct, own, maintain, use and operate the Michigan Wind Projects. As of the date hereof, except as set forth in Section 4.11(c)(iv) of the Seller Disclosure Schedule, Seller reasonably believes that all material Permits necessary for the development, construction, ownership, maintenance, use and/or operation of the Michigan Wind Projects (including material Permits with respect to applicable zoning and land use Laws) can be obtained in the ordinary course. Buyer acknowledges that not all such Permits required for the Michigan Wind Projects are known as of the date of this Agreement.

(d) Title Insurance Policies. The title insurance policies and surveys listed in Section 1.1(f) of the Seller Disclosure Schedule are all of the title insurance policies and surveys the Acquired Companies and their Affiliates with respect to the Owned Real Property and the Acquired Companies’ interests granted under the Occupied Real Property. True and complete copies of such title insurance policies and surveys have been delivered or made available to Buyer.

(e) Michigan Wind Projects Interconnection. Except as set forth in Section 4.11(e) of the Seller Disclosure Schedule, as of the date hereof, to Seller’s Knowledge (i) no material impediment exists to interconnecting any Michigan Wind Project to the applicable transmission system, (ii) the cost allocation of such interconnection (including the cost of network upgrades) will be on the same basis in all material respects as the Acquired Companies’ operating wind projects located in the State of Michigan, except solely with respect to the Harvest II Windfarm Project and the Blissfield Wind Project for differences that may result from changes in events or circumstances outside of Seller’s reasonable control, (iii) no transmission provider or regional transmission organization has changed or proposed any changes to modify, in any material respect, the cost allocation of interconnection (including the cost of network upgrades) for the Michigan Wind Projects from that utilized in connection with the operating wind projects in the State of Michigan and (iv) no Acquired Company has received notice of any changes or proposed changes with respect to, or any notice of disputes regarding, the cost allocation of interconnection (including the cost of network upgrades) for the Michigan Wind Projects from that utilized in connection with the operating wind projects in the State of Michigan.

Section 4.12 Environmental Matters.

(a) Except as set forth in Section 4.12 of the Seller Disclosure Schedule:

(i) each of the Acquired Companies is and, to Seller’s Knowledge at all times has been, in material compliance with applicable Environmental Laws and Environmental Permits;

(ii) each Acquired Company possesses all Environmental Permits required for the ownership, construction, use and operation of the Acquired Companies’ wind energy projects in commercial operation; all such Environmental Permits are valid and in full force and effect; and there is no Action pending or, to Seller’s Knowledge, threatened to revoke or terminate any such Environmental Permit, or to modify in a materially adverse manner any such Environmental Permit that is material to (A) the Acquired Companies taken as a whole, (B) the operation of any material portion of the Business or (C) the operation of the Business taken as a whole;

(iii) to Seller’s Knowledge, there are no facts, circumstances or conditions that reasonably could adversely affect continued compliance with any existing Environmental Permit that is material to (A) the Acquired Companies taken as whole, (B) the operation of any material portion of the Business or (C) the operation of the Business taken as a whole;

(iv) with respect to each Acquired Company, at all times (A) while Seller or any of its Affiliates has owned or otherwise held a majority interest in such Acquired Company, and (B) to Seller’s Knowledge, prior to the date on which Seller or any of its Affiliates first owned or otherwise held such interest in such Acquired Company, such Acquired Company has not received written notice of, and is not subject to, any Action or Order, and to Seller’s Knowledge, no Action or Order is threatened, relating to non-compliance with any Environmental Law or Environmental Permit;

(v) with respect to each Acquired Company, at all times (A) while Seller or any of its Affiliates has owned or otherwise held a majority interest in such Acquired Company, and (B) to Seller’s Knowledge, prior to the date on which Seller or any of its Affiliates first owned or otherwise held such interest in such Acquired Company, such Acquired Company has not received notice of, and is not otherwise subject to, any Action or Order, and to Seller’s Knowledge, no Action or Order is threatened, relating to any Release, threatened Release, or cleanup of Hazardous Substances under any Environmental Law, which in either case would reasonably be expected to result in Losses material to (x) the Acquired Companies taken as a whole, (y) the operation of any material portion of the Business or (z) the operation of the Business taken as a whole;

(vi) to Seller’s Knowledge, no Hazardous Substance is present at, on or under the Owned Real Property or the Occupied Real Property in a condition that would reasonably be expected to result in material Losses to Seller or any Acquired Company under Environmental Law;

(vii) to Seller’s Knowledge, no Release of Hazardous Substances has occurred from the Owned Real Property or the Occupied Real Property, including into waters, at, on, under or adjacent to the Owned Real Property or the Occupied Real Property or onto lands from which Hazardous Substances might seep, flow or drain into such waters, in a manner or condition that would reasonably be expected to result in material Losses to Seller or any Acquired Company under or relating to any Environmental Law; and

(viii) Seller has delivered or made available to Buyer true and complete copies and results of any material written reports, studies, investigations, analyses, tests or monitoring possessed by or in the control of Seller, any Acquired Company in the Wholly-Owned Group or, to Seller’s Knowledge, any Acquired Company in the Partially-Owned Group, with respect to any matters arising under any Environmental Law or Environmental Permit and relating to any Acquired Company.

(b) Notwithstanding the generality of any other representations or warranties contained in this Agreement, this Section 4.12 will be deemed to contain the only representations and warranties in this Agreement with respect to environmental matters, Environmental Permits or Environmental Laws.

Section 4.13 Intellectual Property.

(a) Section 4.13(a) of the Seller Disclosure Schedule sets forth, for the Intellectual Property owned by the Acquired Companies as of the date hereof, a complete and true list of all U.S. and foreign: (i) patents and patent applications, (ii) material trademark registrations and applications (including Internet domain names), and (iii) material copyright registrations and applications (together with all other Intellectual Property owned by any of the Acquired Companies, the “Company Intellectual Property”), indicating for each item the registration or application number, the record owner, and the applicable filing jurisdiction.

(b) Except as set forth in Section 4.13(b) of the Seller Disclosure Schedule, the Acquired Companies own, or are validly licensed or otherwise have the right to use, all Intellectual Property used in the conduct of the Business free and clear of all Encumbrances (other than Permitted Encumbrances described in clause (iv) of the definition of Permitted Encumbrances) except where the failure to own the same or to be validly licensed or otherwise have the right to use the same would not reasonably be expected to be material to (i) the Acquired Companies taken as a whole, (ii) the operation of any material portion of the Business or (iii) the operation of the Business taken as a whole; provided that, for the avoidance of doubt, the foregoing shall not be deemed to constitute a representation or warranty with respect to infringement or other violation of

Intellectual Property of a third party, which is addressed in Section 4.13(c). No claims are pending or, to Seller’s Knowledge, threatened as of the date hereof that any of the Acquired Companies are infringing, misappropriating, violating or otherwise adversely affecting in any material respect the rights of any Person with regard to any Intellectual Property, and except with respect to any claims that have been resolved, the Acquired Companies have not sent to any third party any notice of infringement or misappropriation of or conflict with any of the Acquired Companies’ rights with respect to any Company Intellectual Property.

(c) To Seller’s Knowledge, the Acquired Companies have not infringed and are not infringing the Intellectual Property rights of any third party in any material respect. To Seller’s Knowledge, no person is infringing the rights of the Acquired Companies with respect to any material Company Intellectual Property.

(d) The Acquired Companies’ material information technology systems operate and perform in all material respects as required by the Acquired Companies in connection with the Business as currently conducted. The Acquired Companies have taken in all material respects reasonable measures to protect the confidentiality, integrity and security of their material information technology systems from any unauthorized and malicious use, access, interruption or modification by third parties. Except as set forth in Section 4.13(d) of the Seller Disclosure Schedule, all information technology systems used by any of the Acquired Companies in connection with the Business are owned or licensed by one or more of the Acquired Companies, and the Acquired Companies have implemented reasonable backup, security and disaster recovery technology and procedures with respect to all material information technology systems used by the Acquired Companies in connection with the Business, which technology and procedures are consistent in all material respects with Prudent Industry Practices.

(e) No settlement agreements, consents, orders, forbearances to sue or similar obligations to which any Acquired Company is a party limit or restrict any rights of the Acquired Companies in and to any Company Intellectual Property in any material respect.

(f) Except as set forth in Section 4.13(f) of the Seller Disclosure Schedule, the consummation of the Transactions will not result in the loss or material impairment of any rights of the Acquired Companies to own or use any material Intellectual Property or obligate the Acquired Companies to pay any royalties or other amounts to any third party in excess of the amounts that would have been payable by them absent the consummation of the Transactions.

Section 4.14 Affiliate Transactions. Except as set forth in Section 4.14 of the Seller Disclosure Schedule, none of the Acquired Companies is a party to any Contract or transaction with any of its current employees, officers, directors, Affiliates (including Seller) or shareholders, other than transactions with other Acquired Companies (including the incurrence of the Target Company Intercompany Debt) or whereby Seller has purchased equity interests in any of the Acquired Companies and any

employment and similar arrangements entered into in the ordinary course of business consistent with past practice.

Section 4.15 Insurance. Section 4.15 of the Seller Disclosure Schedule lists all current insurance policies held by or that insure the Acquired Companies or any of their respective assets or properties (the “Insurance Policies”), and such list identifies which Person actually holds such insurance. With respect to each Acquired Company, at all times (a) while Seller or any of its Affiliates has owned or otherwise held any interest in such Acquired Company, and (b) to Seller’s Knowledge, prior to the date on which Seller or any of its Affiliates first owned or otherwise held such interest in such Acquired Company, insurance has been maintained by or on behalf of such Acquired Company with financially responsible and reputable insurers or through self-insurance, in each case as customary for companies of similar size in the United States of America conducting the business conducted by the Acquired Companies, in the normal course of business, throughout its operations. To Seller’s Knowledge, nothing should prohibit Buyer’s placement of similar insurance after the Closing. All premiums due and payable under all the Insurance Policies have been paid and Seller and its subsidiaries (including the Acquired Companies) are otherwise in compliance in all material respects with the terms of the Insurance Policies. None of Seller or its subsidiaries (including the Acquired Companies) has received any written or, to Seller’s Knowledge, oral notice of cancellation, termination or material premium increase (outside the ordinary course of business consistent with past practice) with respect to any of the Insurance Policies, or of any material changes that are required in the conduct of the Business of the Acquired Company as a condition to the continuation of coverage under, or renewal of, any of the Insurance Policies. Except as set forth in Section 4.15 of the Seller Disclosure Schedule, as of the date hereof, there are no pending material claims under the Insurance Policies by the Acquired Companies.

Section 4.16 Absence of Certain Changes. Since July 31, 2010, (a) there has not occurred any Material Adverse Effect, the Acquired Companies have carried on and operated their respective businesses in the ordinary course of business consistent with past practice, and (b) no action, event, occurrence, transaction or omission to take any action has taken place or occurred that would have been prohibited by Sections 6.3(a), (b), (c), (k), (l), (m), (o), (r) or (s) if this Agreement had been in effect at the time thereof.

Section 4.17 Hedging. Other than power purchase agreements and renewable energy credit purchase and sale agreements listed in Section 4.6(a) of the Seller Disclosure Schedule, none of the Acquired Companies engages in any physical or financial electricity hedge contracts, currency or interest rate hedge contracts, exchange-traded futures or options transactions, over-the-counter transactions or derivatives thereof, interest rate swap agreements or similar transactions.

Section 4.18 Indebtedness; Credit Support Arrangements; Outstanding Payment Obligations.

(a) Section 4.18(a) of the Seller Disclosure Schedule sets forth, in each case as of July 31, 2010, (a) all outstanding Third-Party Debt, (b) all outstanding Seller Intercompany Debt and (c) all outstanding Target Company Intercompany Debt. Section 4.18(a) of the Seller Disclosure Schedule also contains a correct and complete list of all Existing Credit Support and the Contracts pursuant to which such Existing Credit Support was issued.

(b) Except as set forth in Section 4.18(b) of the Seller Disclosure Schedule, at the Closing, the Acquired Companies will not have any Third-Party Debt.

Section 4.19 Foreign Corrupt Practices Act. None of the Acquired Companies or any of their respective directors, officers, agents, employees or any other Persons acting on their behalf has, in connection with the operation of their respective businesses, (a) used any corporate or other funds for unlawful contributions, payments, gifts or entertainment, or made any unlawful expenditures relating to political activity to officials, candidates or members of any Governmental Entity or political party or organization, or established or maintained any unlawful or unrecorded funds in violation of Section 104 of the Foreign Corrupt Practices Act of 1977, as amended, or any other similar applicable Law, (b) paid, accepted or received any unlawful contributions, payments, expenditures or gifts, or (c) violated in any material respect or operated in material non-compliance with any export restrictions, anti-boycott regulations, embargo regulations or other applicable Laws.

Section 4.20 Officers and Managers; Bank Accounts. Section 4.20 of the Seller Disclosure Schedule lists all directors, managers and officers of the Acquired Companies and all bank accounts, safety deposit boxes and lock boxes (designating each authorized signatory with respect thereto) for each Acquired Company.

Section 4.21 Turbine Warranties.

(a) Section 4.21(a) of the Seller Disclosure Schedule sets forth a true, correct and complete list of all material agreements between Suzlon and Seller (or any Affiliate of Seller) relating to the Suzlon wind turbines owned by any Acquired Company (collectively, the “Fleet”), including without limitation all turbine supply agreements, warranty service agreements, operations and maintenance agreements, the correspondence from Suzlon to Target Company dated July 9, 2010 and July 27, 2010, and the correspondence from Suzlon to John Deere Wind Energy dated June 17, 2010 (collectively, the “Suzlon Agreements”). The terms set forth in each of the amendments to the master agreements and the correspondence listed on Section 4.21(a) of the Seller Disclosure Schedule apply to the Suzlon Agreements as if such terms were set forth in an amendment to an Acquired Company specific turbine supply agreement, warranty services agreement and/or operations and maintenance agreement, as applicable.

(b) Section 4.21(b) of the Seller Disclosure Schedule lists each of the S-88 V-2 blades that were replaced or retrofitted in connection with the Blade Crack Problem (collectively, the “S-88 Blades”).

(c) Section 4.21(c) of the Seller Disclosure Schedule sets forth a true, correct and complete list of (i) the date of commencement of the warranty period for operating Suzlon wind turbines owned by the Acquired Companies and of the warranty period for their availability (the “Equipment and Availability Warranty Commencement Dates”), (ii) the date of expiration of the warranty period for operating Suzlon wind turbines owned by the Acquired Companies (other than S-88 Blades) and the date of expiration of the warranty period for their availability (the “Equipment and Availability Warranty Expiration Dates”), (iii) the annual fee per operating Suzlon wind turbine for the applicable extended warranty period, and (iv) the date of expiration of the warranty period for the S-88 Blades as of the date hereof (the “Blade Warranty Expiration Dates”).

(d) The terms of each of the warranty service agreements and operations and maintenance agreements that are Suzlon Agreements end no earlier than the Equipment and Availability Warranty Expiration Dates applicable to the operating wind turbines subject to such warranty service agreements and operations and maintenance agreements, other than as specifically set forth in such agreements.

(e) None of the Acquired Companies is required to pay any fees or other amounts for the warranties, warranty services agreements or operations and maintenance agreements applicable to the S-88 Blades for the period between the applicable Equipment and Availability Warranty Expiration Date and Blade Warranty Expiration Date, other than Suzlon’s costs for visual inspection of blades and inspection of blade bolt torque to slew rings and such other amounts which may arise in the normal course of business in accordance with the Suzlon Agreements.

(f) Except as set forth in Section 4.21(f) of the Seller Disclosure Schedule, all S-88 Blades that are installed as of the date hereof have extended equipment warranties of at least seven (7) years following the applicable Equipment and Availability Warranty Commencement Dates. All S-88 Blades with Blade Warranty Expiration Dates that are seven (7) years following the applicable Equipment and Availability Warranty Commencement Dates were replaced prior to the date hereof with blades incorporating into the design of such blades a fix to the Blade Crack Problem. All S-88 Blades with Blade Warranty Expiration Dates that are twenty (20) years following the applicable Equipment and Availability Warranty Commencement Dates were repaired or stiffened prior to the date hereof.

(g) Except as set forth in Section 4.21(g) of the Seller Disclosure Schedule, as of the date hereof, (i) no payments are owed to Suzlon by Seller or its Affiliates, and (ii) there is no outstanding guarantee, letter of credit or other credit support for Seller or any of its Affiliates in favor of Suzlon or any of its Affiliates.

(h) Suzlon is not holding any deposits relating to the Fleet made by or on behalf of Seller or its Affiliates.

(i) The Acquired Companies have received from Suzlon and made available to Buyer all of the Germanischer Lloyd type certificates listed in

Section 4.21(i) of the Seller Disclosure Schedule for the types of wind turbines described on such certificates, and Seller does not expect to receive any additional Germanischer Lloyd type certificates from Suzlon.

(j) As of the date hereof, there are no actions, disputes or other proceedings pending or, to Seller’s Knowledge, threatened between Suzlon and any Acquired Company.

(k) Seller has made available to Buyer true and complete copies of all technical reports, studies and investigations in its or any of its Affiliates’ possession, which were material for Seller or any of its Affiliates to evaluate the Blade Crack Problem.

(l) Section 4.21(l)(i) of the Seller Disclosure Schedule sets forth the amounts paid as of the date hereof by Suzlon to each of the Acquired Companies pursuant to the Suzlon Agreements. Suzlon has paid all availability claims submitted to Suzlon by or on behalf of an Acquired Company. Except as set forth in Section 4.21(l)(ii) of the Seller Disclosure Schedule, no costs associated with any past or future S-88 Blade warranty repairs or replacements have been or will be applied against any of the caps for liabilities contained in the Suzlon Agreements.

Section 4.22 Regulatory Reporting. Except as set forth in Section 4.22 of the Seller Disclosure Schedule, (a) since January 1, 2007, each Acquired Company has filed or caused to be filed with the applicable state or local utility commissions or regulatory bodies, FERC and any other Governmental Entity with jurisdiction over the Acquired Companies and their respective Businesses, assets, properties and liabilities, as the case may be, all material forms, statements, reports, and documents (including all exhibits, amendments and supplements thereto) required under all applicable Laws to be filed by any Acquired Company with respect to itself or its Business, assets, properties or liabilities, and (b) all such forms, statements, reports, and documents that were filed complied in all materials respects with all applicable requirements of the Laws in effect on the date of such filing, and there are no material misstatements or omissions in any such form, statement, or report. Further, each Acquired Company which owns generation facilities has obtained either qualifying facility status pursuant to the Public Utility Regulatory Policies Act of 1978 and 18 C.F.R. Part 292, exempt wholesale generator status pursuant to 18 C.F.R. § 366.7, and/or market based rate authority pursuant to Section 205 of the Federal Power Act as necessary to conduct its business in compliance with all applicable Laws. To Seller’s Knowledge, each Acquired Company subject to NERC standards or requirements is in compliance in all material respects with such standards or requirements.

Section 4.23 Project Acquisitions. Except as set forth in Section 4.23 of the Seller Disclosure Schedule, there are no outstanding purchase price payments or purchase price adjustments (including earn-outs and similar post-closing adjustments) to be made to any Person with respect to any transaction by which Seller or any of the Acquired Companies or any other Affiliate of Seller acquired any right or interest in, to or under any of the Acquired Companies or the Development Projects.

Section 4.24 No Other Representations. Except for the representations and warranties expressly made by Seller in Article III hereof and in this Article IV (including, in each case, the Seller Disclosure Schedule), none of Seller, the Acquired Companies, or any other Person makes any express or implied representation or warranty on behalf of or with respect to Seller, the Acquired Companies, the Transferred Interests or the Business, and Seller hereby disclaims any representation or warranty not contained in Article III or this Article IV. Without limiting the generality of the foregoing, it is understood that any cost estimates, financial or other projections or other predictions that may be contained or referred to in the Seller Disclosure Schedule or elsewhere, as well as any information, documents or other materials (including any such materials contained in any “data room” or any “confidential information memorandum” or reviewed by Buyer pursuant to the Confidentiality Agreement) or management presentations that have been or shall hereafter be provided to Buyer or any of its Affiliates or Representatives are not and will not be deemed to be representations or warranties of Seller or the Acquired Companies, and no representation or warranty is made as to the accuracy or completeness of any of the foregoing except as may be expressly set forth in this Agreement.

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer hereby represents and warrants to Seller as follows:

Section 5.1 Due Organization and Good Standing. Buyer is a limited liability company duly organized, validly existing and in good standing under the laws of the Commonwealth of Pennsylvania. Buyer has previously made available to Seller complete and correct copies of the certificate of organization and operating agreement of Buyer, as amended to the date hereof, and such certificate of organization and operating agreement, as so made available to Buyer, are in full force and effect, and Buyer is not in violation of its certificate of organization or operating agreement, except in each case as would not, or would not be reasonably expected to, individually or in the aggregate, impair in any material respect Buyer’s ability to perform its obligations under this Agreement or to consummate the transactions contemplated hereby.

Section 5.2 Authorization of Transaction. Buyer has full power and authority to execute and deliver this Agreement, to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby have been duly and validly authorized by all required limited liability company or other action on the part of Buyer and no other limited liability company or other proceedings on the part of Buyer are necessary to authorize the execution, delivery and performance of this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly executed and delivered by Buyer and constitutes (assuming the due execution and delivery by Seller) a valid and legally binding obligation of Buyer, enforceable in accordance with its terms, except as such enforcement may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar Laws relating to or affecting the rights and remedies of creditors generally and subject to general principles of equity (whether considered in a proceeding at law or in equity).

Section 5.3 Approvals. No filing or registration with, notification to, or authorization, consent, approval or waiver of any Governmental Entity is required or otherwise necessary for the execution, delivery and performance of this Agreement by Buyer or the consummation by Buyer of the transactions contemplated hereby, except (a) as set forth in Section 5.3 of the Buyer Disclosure Schedule, (b) filings under the HSR Act, (c) filings that become applicable as a result of matters specifically related to Seller or its Affiliates or (d) filings with and approvals from FERC (such Governmental Entity filings, registrations, notifications, authorizations, consents or approvals set forth in clauses (a) through (d) above being hereinafter referred to collectively as the “Buyer Required Approvals”) or (e) such other Governmental Entity filings, registrations, notifications, authorizations, consents or approvals the failure of which to be obtained or made would not, or would not be reasonably expected to, individually or in the aggregate, impair in any material respect Buyer’s ability to perform its obligations under this Agreement or to consummate the transactions contemplated hereby.

Section 5.4 Brokers’ Fees. Neither Buyer nor any of its directors (or Persons in similar positions), officers, employees or agents has employed any broker or finder or incurred any liability for any investment banking fees, brokerage fees, commissions or finders’ fees in connection with the transactions contemplated by this Agreement for which Seller would have any liability or otherwise be liable.

Section 5.5 Legal Proceedings. As of the date hereof, there are no Actions pending or, to Buyer’s Knowledge, threatened against Buyer (or any of its respective officers or directors), which, if adversely determined, would, or would be reasonably expected to, individually or in the aggregate, impair in any material respect the ability of Buyer to perform its obligations hereunder. As of the date hereof, there are no such Actions pending or, to Buyer’s Knowledge, threatened challenging the validity or propriety of, or seeking to prevent, enjoin or materially delay consummation of, the transactions contemplated hereby. Buyer is not subject to any Orders, which would, or would be reasonably expected to, individually or in the aggregate, impair in any material respect the ability of Buyer to perform its obligations hereunder.

Section 5.6 No Conflict or Violation. The execution, delivery and performance of this Agreement by Buyer and the consummation of the transactions contemplated hereby will not, assuming all Buyer Required Approvals have been obtained, (a) violate any applicable Law or Order applicable to Buyer, (b) constitute or result in a Violation of the certification of organization or operating agreement of Buyer, or (c) constitute or result in a Violation or amendment, cancellation, suspension or acceleration under, or resulting in a loss of any benefit under, any material Contract to which Buyer is a party or by which any of its properties or assets may be bound or affected, except in the case of clauses (a) and (c), for such Violations as would not, or would not be reasonably expected to, individually or in the aggregate, impair in any material respect the ability of Buyer to perform its obligations hereunder or prevent or materially delay consummation of the transactions contemplated hereby.

Section 5.7 Acquisition of Interests for Investment. Buyer acknowledges that neither the offer nor the sale of the Transferred Interests has been registered under the Securities Act of 1933, as amended (together with the rules and regulations promulgated thereunder, the “Securities Act”), or under any state or foreign securities Laws. Buyer has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of its purchase of the Transferred Interests. Buyer confirms that Seller and the Acquired Companies have provided Buyer the opportunity to ask questions of the officers and management employees of Seller and the Acquired Companies and to acquire additional information about the business and financial condition of the Acquired Companies. Buyer is acquiring the Transferred Interests for its own account for investment, without a view to, or for a resale in connection with, the distribution thereof in violation of the Securities Act or any applicable state securities Laws and with no present intention of distributing or reselling any part thereof. Buyer will not so distribute or resell any of the Transferred Interests in violation of any such Law. Buyer acknowledges and understands that the Transferred Interests are not registered under the Securities Act.

Section 5.8 Sufficient Funds. Buyer has as of the date hereof, and shall have on the Closing Date, sufficient funds to enable Buyer to consummate the transactions contemplated hereby, including payments required at Closing pursuant to Section 2.2 and fees and expenses of Buyer relating to the transactions contemplated hereby.

Section 5.9 Solvency. After giving effect to the transactions contemplated hereby, and assuming the accuracy of the representations and warranties made by Seller in this Agreement in all respects, Buyer will not (a) be insolvent (either because its financial condition is such that the sum of its debts is greater than the fair value of its assets or because the present fair saleable value of its assets will be less than the amount required to pay its probable liability on its debts as they become absolute and matured), (b) have unreasonably small capital with which to engage in its business, or (c) have incurred or plan to incur debts beyond its ability to pay as they become absolute and matured.

Section 5.10 Inspections. Buyer (directly or through its Affiliates and advisors) is an informed and sophisticated purchaser, and has engaged expert advisors, experienced in the evaluation and purchase of the companies such as the Acquired Companies as contemplated hereunder. Buyer (directly or through its Affiliates) has undertaken such investigation as it has deemed necessary to enable it to make an informed and intelligent decision with respect to the execution, delivery and performance of this Agreement.

Section 5.11 Tax Status. Buyer is indirectly wholly-owned by Exelon Corporation, an entity treated as a corporation for U.S. federal and state income Tax purposes.

Section 5.12 No Other Representations. Except for the representations and warranties expressly made by Buyer in this Article V (including, in each case, the

Buyer Disclosure Schedule), neither Buyer nor any other Person makes any express or implied representation or warranty on behalf of or with respect to Buyer, and Buyer hereby disclaims any representation or warranty not contained in this Article V.

ARTICLE VI

COVENANTS

Section 6.1 Publicity. Buyer and Seller agree to communicate with each other and cooperate with each other prior to any public disclosure of this transaction. Buyer and Seller agree that no public release or announcement concerning the terms of the transactions contemplated hereby shall be issued by any party without the prior consent of Buyer and Seller, except as such release or announcement may be required by Law or applicable securities or exchange rules, in which case the party required to make the release or announcement shall allow, to the extent practicable, the other party reasonable time to comment on such release announcement in advance of such issuance. Nothing contained herein, however, shall preclude Seller or Buyer from filing a copy of this Agreement as an exhibit to its filings with the U.S. Securities and Exchange Commission.

Section 6.2 Confidentiality; Non-Competition; Non-Solicitation.

(a) Confidentiality Agreement. The Confidentiality Agreement shall continue in full force and effect until the Closing Date, on which date the Confidentiality Agreement shall terminate and cease to be of any further force or effect.

(b) Post-Closing Obligations. Following the Closing Date, and except as provided in Section 6.2(c) of this Agreement, (i) Buyer agrees not to disclose or allow disclosure to others of any Seller Confidential Information for a period of two (2) years after the Closing Date, except that Buyer may disclose Seller Confidential Information to its Affiliates and Representatives, provided that Buyer shall be responsible for any breach of the applicable terms of this Section 6.2(b) by any of its Affiliates or Representatives to which it disclosed Seller Confidential Information, and (ii) Seller agrees not to disclose or allow disclosure to others of any Buyer Confidential Information for a period of two (2) years after the Closing Date, except that Seller may disclose Buyer Confidential Information to its Affiliates and Representatives, provided that Seller shall be responsible for any breach of the applicable terms of this Section 6.2(b) by any of its Affiliates or Representatives to which it disclosed Buyer Confidential Information.

(i) In the event that Buyer or any of its Representatives is requested or required by deposition, interrogatory, request for documents, subpoena, civil investigative demand, or similar legal process to disclose any Seller Confidential Information, Buyer shall provide Seller with prompt prior

written notice of such requirement, which notice shall include the terms and circumstances surrounding such requested or required disclosure, in order to enable Seller to (A) seek an appropriate protective order or other remedy or (B) waive compliance, in whole or in part, with this Section 6.2; and Buyer shall consult and reasonably cooperate with Seller to the fullest extent permitted by Law with respect to taking steps to resist or narrow the scope of such request or legal process. If, in the absence of a protective order, Buyer or any of its Representatives believes in good faith, after consulting with counsel, that it is, nonetheless, required by Law to disclose Seller Confidential Information, Buyer shall (or shall cause its Representatives to) (x) furnish only that portion of the Seller Confidential Information that, Buyer or its Representatives believe, after consulting with counsel, is legally required, and (y) give advance notice to Seller of the information to be disclosed as far in advance as is practical. All costs and expenses of Buyer and its Representatives relating to this Section 6.2(c)(i) shall be borne by Seller.

(ii) In the event that Seller or any of its Representatives is requested or required by deposition, interrogatory, request for documents, subpoena, civil investigative demand, or similar legal process to disclose any of the Buyer Confidential Information, Seller shall provide Buyer with prompt prior written notice of such requirement, which notice shall include the terms and circumstances surrounding such requested or required disclosure, in order to enable Buyer to (i) seek an appropriate protective order or other remedy or (ii) waive compliance, in whole or in part, with this Section 6.2; and Seller shall consult and reasonably cooperate with Buyer to the fullest extent permitted by Law with respect to taking steps to resist or narrow the scope of such request or legal process. If, in the absence of a protective order, Seller or any of its Representatives believes in good faith, after consulting with counsel, that it is, nonetheless, required by Law to disclose Buyer Confidential Information, Seller shall (or shall cause its Representatives to) (x) furnish only that portion of the Buyer Confidential Information that, Seller or its Representatives believe, after consulting with counsel, is legally required, and (y) give advance notice to Buyer of the information to be disclosed as far in advance as is practical. All costs and expenses of Seller and its Representatives relating to this Section 6.2(c)(ii) shall be borne by Buyer.

(d) Non-Competition. Seller agrees that, for a period of three (3) years following the Closing Date, Seller shall not, and shall cause all of Seller’s Affiliates not to, (i) engage as an owner, operator, manager or developer of a business constituting the Business or any portion thereof or (ii) provide any consulting services regarding or relating to wind-powered generating facilities. Nothing in this Section 6.2(d), however, shall prevent Seller from (1) generating electricity ancillary to its manufacturing facilities or other business operations or (2) supplying feedstock, managing related fuel yards or providing services ancillary thereto.

(e) Non-Solicitation. Seller agrees that, for a period of eighteen (18) months following the Closing Date (the “Restricted Period”), Seller shall

not, and shall not permit any of its Affiliates to, directly or indirectly: (i) contact, approach or solicit for the purpose of offering employment to or of hiring (whether as an employee, consultant, agent, independent contractor or otherwise) or hire any Designated Employee who was employed by Seller or any of its Affiliates within the twelve (12) month period prior to the Closing Date or during the Restricted Period, without the prior written consent of Buyer, except as set forth in Section 6.2(e) of the Seller Disclosure Schedule; provided that nothing herein shall be construed as restricting Seller from engaging in a general solicitation of employment not specifically directed at any Designated Employee (for the avoidance of doubt, during the Restricted Period, neither Seller nor any of its Affiliates may hire any Designated Employee who responds to, or otherwise seeks employment with Seller or its Affiliates as a result of, such general solicitation); or (ii) induce or attempt to induce any customer, supplier, licensee, licensor or other business relation of the Acquired Companies to cease doing business with the Acquired Companies, or in any way materially interfere with the relationship between any such customer, supplier, licensee or business relation, on the one hand, and the Acquired Companies, on the other hand (including, without limitation, making any disparaging statements or communications regarding the Acquired Companies).

(f) Remedy for Breach. Seller acknowledges and agrees that in the event of a breach by Seller of any of the provisions of this Section 6.2, the Acquired Companies and Buyer would be irreparably harmed and monetary damages shall not constitute a sufficient remedy. Consequently, in the event of any such breach, the Acquired Companies, Buyer and/or their respective successors or assigns may, in addition to other rights and remedies existing in their favor, apply to any court of law or equity of competent jurisdiction for specific performance and/or injunctive or other relief in order to enforce or prevent any violations of the provisions of this Section 6.2, in each case without the requirement of posting a bond or proving actual damages.

(g) Enforcement. If the final judgment of a court of competent jurisdiction declares that any term or provision of Section 6.2 is invalid or unenforceable, the parties agree that, to the extent permitted under applicable Law, the court making the determination of invalidity or unenforceability shall have the power to reduce the scope, duration, or area of the term or provision, to delete specific words or phrases, or to replace any invalid or unenforceable term or provision with a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision, and this Agreement shall be enforceable as so modified after the expiration of the time within which the judgment may be appealed.

(h) Acknowledgment. Seller acknowledges and agrees that (i) the covenants and agreements set forth in Sections 6.2(d) and 6.2(e) are in additional consideration of the agreements and covenants of Buyer and Seller hereunder and were a material inducement to Buyer to enter into this Agreement and to perform its obligations hereunder, and that Buyer and its Affiliates would not obtain the benefit of the bargain set forth in this Agreement as specifically negotiated by the parties if Seller or its Affiliates breached the provisions set forth in Sections 6.2(d) or 6.2(e), and (ii) the restrictions contained in Sections 6.2(d) and 6.2(e) are reasonable in all respects (including with respect to subject matter, time period and geographical area) and are necessary to protect

Buyer’s interest in, and the value of, the Transferred Interests and the Acquired Companies (including, the goodwill inherent therein). Seller further acknowledges and agrees that Seller is the record and beneficial owner of the Transferred Interests and, as such, will obtain a substantial benefit from the consummation of the transactions contemplated hereby.

Section 6.3 Conduct of the Acquired Companies’ Business. Seller agrees that, during the period from the date hereof until the earlier of the Closing Date or the termination of this Agreement, except as (i) otherwise contemplated by this Agreement, (ii) set forth in Section 6.3 of the Seller Disclosure Schedule, (iii) consented to by Buyer in writing (which consent shall not be unreasonably withheld, delayed or conditioned), or (iv) required by any Contract to which Seller or the Acquired Companies are party or by any Law, Seller (x) shall cause the Acquired Companies to conduct their respective business and operations in the ordinary course of business consistent with past practice and consistent with Prudent Industry Practices, and (y) subject to the foregoing, shall not with respect to the Business, and shall cause each of the Acquired Companies in the Wholly-Owned Group not to, and to the extent within the power of Seller, shall cause each of the Acquired Companies in the Partially-Owned Group not to, and to the extent Seller does not have such power with respect to such Acquired Companies in the Partially-Owned Group, shall use its commercially reasonable efforts to cause each such Acquired Company in the Partially-Owned Group not to, as applicable:

(a) authorize or effect any change in any Acquired Company’s Charter Documents in any manner adverse to Buyer;

(b) (1) acquire any membership interests or securities to be owned by or on behalf of the Acquired Companies, or (2) redeem, issue, sell or otherwise dispose of any of the Transferred Interests or any of the membership interests (or other ownership interests) of the Acquired Companies;

(c) issue any note, bond, or other debt security or create, incur, assume, or guarantee any indebtedness for borrowed money or capitalized lease obligation that in each case is Indebtedness of an Acquired Company, other than Seller Intercompany Debt and Target Company Intercompany Debt incurred in the ordinary course of business consistent with past practice, or enter into any physical or financial electricity hedge contracts, currency or interest rate hedge contracts, exchange-traded futures or options transactions, over-the-counter transactions or derivatives thereof, interest rate swap agreements or similar transactions;

(d) issue or procure outside the ordinary course of business consistent with past practice any new guarantee or letter of credit that would constitute Existing Credit Support under this Agreement that will continue to be in effect beyond the Closing Date;

(e) cancel, compromise or settle any material claim, or waive or release any material rights, of any Acquired Company or relating to the Business, including the Texas PURPA Action;

(f) enter into, adopt, amend, alter, or terminate any Employee Benefit Plan, except as required to maintain qualification under, or to otherwise comply with the requirements of, the Code, applicable Law or the terms of any Employee Benefit Plan as in effect on the date hereof; provided, that nothing contained herein shall prohibit Seller from taking actions generally applicable to employees of Seller and its Affiliates in the ordinary course of business;

(g) authorize, grant or agree to grant, guarantee, offer or pay any increase in the wages, salary, bonus or other compensation, remuneration or benefits of any Company Employee or director of the Acquired Companies except (1) as required under applicable Law or any Employee Benefit Plan as in effect on the date hereof, (2) pursuant to the Acquired Companies regularly scheduled annual salary increases or (3) with respect to Company Employees other than officers, directors or managers, in the ordinary course of business consistent with past practice;

(h) subject to Section 6.8(a), transfer the employment of any individual to (y) any Acquired Company from Seller or any of its Affiliates or (z) the Seller or any of its Affiliates from any Acquired Company, or otherwise materially change the job functions of any individual, so as to either (i) cause such individual who is a Designated Employee to cease to be a Designated Employee or (ii) cause such individual who is not a Designated Employee to become a Designated Employee;

(i) subject to Section 6.8(a), terminate the employment (other than for cause) of any individual who is or would be a Company Employee whose employment is or would be on terms that could reasonably be expected to result in the payment of total annual compensation in excess of $150,000;

(j) hire any individual who would be a Company Employee on any basis other than an “at-will” employment or offer or promise any severance benefits or similar benefits payable upon termination of employment to any individual who is or would be a Company Employee;

(k) adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization;

(l) acquire (by merger, amalgamation, consolidation or acquisition of stock or assets) any corporation, partnership or other business organization or division thereof or collection of assets constituting all or substantially all of a business or business unit;

(m) acquire the interests of any minority interest owner of any Acquired Company unless all purchase price payment obligations, including any post-closing payment obligations with respect to purchase price adjustment, earn-outs or other similar payment obligations with respect to such acquisition are fully satisfied prior to the Closing Date or would be reflected as Current Liabilities on the Closing Balance Sheet;

(n) with respect to the Acquired Companies or the income, assets or operations of the Acquired Companies, except as consistent with past practice:

(i) make any changes in reporting for Taxes or Tax accounting methods; (ii) make or rescind any material Tax election; (iii) file any material amended Tax Return or claim for refund of material Taxes; (iv) settle or compromise any Tax liability or refund claim other than any such liability or claim that is de minimis; or (v) incur any material liability for Taxes other than in the ordinary course of business;

(o) amend any Material Contract or enter into any Contract that would constitute a Material Contract under this Agreement outside of the ordinary course of business;

(p) with respect to the Development Projects, (i) enter into any Occupancy Agreement on terms materially different than the terms of Occupancy Agreements in effect as of the date hereof, (ii) obtain any Permit that contains materially different requirements or other terms than Permits in effect as of the date hereof, (iii) enter into any interconnection or transmission agreements on terms materially different than the terms of similar agreements in effect as of the date of this Agreement, (iv) enter into any power purchase agreement or (v) without limiting the limitations in subsection (o) of this Section 6.3, amend or waive any right with respect to any of the power purchase agreements in respect of the Michigan Wind Projects (other than a legally-binding, permanent waiver with respect to any automatic termination of any such power purchase agreement);

(q) create or incur any Encumbrance (other than Permitted Encumbrances) on the material properties or assets of the Acquired Companies;

(r) make any material changes with respect to its financial accounting principles or procedures (other than as required by changes in GAAP);

(s) sell, lease, grant or otherwise transfer or dispose of any material assets or properties of the Acquired Companies except in the ordinary course of business consistent with past practice and consistent with Prudent Industry Practices; or

(t) agree or otherwise commit to take any of the actions prohibited by the foregoing clauses (a) through (s).

Section 6.4 Access to Information.

(a) Subject to this Section 6.4, Seller shall, and shall prior to Closing cause the Acquired Companies and their respective Representatives to, afford the Representatives of Buyer reasonable access during normal business hours, in such a manner as to not interfere with normal operations of Seller and the Acquired Companies, to the officers, directors, properties, offices and other facilities of Seller and the Acquired Companies and to all Books and Records, and shall furnish Buyer with all financial, operating and other data and information with respect to the business and properties of the Acquired Companies as Buyer, through its officers, employees or agents, may reasonably request; provided, however, that the foregoing shall not require Seller or the Acquired Companies to provide any such access or furnish any such information that in its reasonable judgment would result in the disclosure of any trade secrets of third parties

or violate any Law or violate any obligations with respect to confidentiality or, in the reasonable judgment of Seller, compromise or constitute a waiver of any attorney-client privilege of Seller or the Acquired Companies. In exercising its rights hereunder, Buyer shall conduct itself so as not to interfere in the conduct of the business of Seller and the Acquired Companies prior to Closing.

(b) From and after the date hereof until the Closing Date, Seller shall, and shall cause the Acquired Companies to, give Buyer prompt written notice of the receipt by Seller or any Acquired Company of (i) any notice of termination of, or intent to terminate, any Material Contract other than any expiration of any such Material Contract in accordance with its terms, or (ii) any notice of any claim or cause of action (including relating to availability) against it, including for liquidated damages or other monetary damages, under any Material Contract (including a power purchase or sale agreement).

(c) From and after the date hereof until the Closing Date, Seller shall give prompt notice to Buyer, and Buyer shall give prompt notice to the Seller, of (i) any representation or warranty made by it contained in this Agreement that is qualified as to materiality becoming untrue or inaccurate in any respect or any such representation or warranty that is not so qualified becoming untrue or inaccurate in any material respect (but, in either case, only to the extent that Seller or Buyer, as the case may be, is aware of such representation or warranty becoming untrue or inaccurate); provided, however, that solely for purposes of this clause (i), in the case of any representation or warranty that is limited to as of the date of this Agreement or some other specific date, the occurrence of such representation and warranty becoming untrue or inaccurate shall be determined as if such limitation as to when such representation and warranty was made was not included therein, or (ii) the failure by it to comply with or satisfy in any material respect any covenant, condition or agreement to be complied with or satisfied by it under this Agreement (but only to the extent that Seller or Buyer, as the case may be, is aware of such failure to so comply with or satisfy such covenant, condition or agreement); provided, however, that no such notification shall affect the representations, warranties, covenants or agreements of the parties or the conditions to the obligations of the parties under this Agreement. In no event shall any failure by Seller or Buyer to provide any such prompt notice entitle the Buyer Indemnified Parties or the Seller Indemnified Parties, as the case may be, to any remedies other than those remedies which such Buyer Indemnified Parties or the Seller Indemnified Parties, as the case may be, are entitled to pursuant to this Agreement as a result of the untrue or inaccurate representation or warranty or failure to comply with or satisfy a particular covenant (other than this Section 6.4(c)), condition or agreement giving rise to Seller’s or Buyer’s, as the case may be, obligation to provide such notice.

(d) From and after the date hereof until the Closing Date, Seller shall deliver or cause to be delivered to Buyer, within five (5) Business Days of being available, copies of any and all (i) regularly prepared final monthly, quarterly and annual financial statements (whether or not audited or consolidated) of the Acquired Companies, (ii) written reports prepared for the monthly business review meeting of the Target Company’s management, (iii) written monthly project operating reports prepared

in the ordinary course of business by the Acquired Companies or Seller or its Affiliates that relate to the Acquired Companies, (iv) material Tax Returns filed with any Governmental Entity by any Acquired Company, and all written material correspondence received from or exchanged with any Governmental Entity by any Acquired Company or with respect to any Acquired Company or its properties, assets or liabilities, notably in respect of any audits, examinations or similar proceedings or any rulings or proposed rulings (the Parties understand that correspondence provided under this clause may include redacted portions of such correspondence that are unrelated to the Acquired Companies), and (v) material filings made by the Acquired Companies with applicable state or local utility commissions or regulatory bodies, FERC and any other Governmental Entity.

(e) As reasonably requested by Buyer from time to time, Seller shall use commercially reasonable efforts to facilitate the transition of the Acquired Companies’ use of Seller’s and its Affiliates’ infrastructure and information technology systems to Buyer’s and its Affiliates’ infrastructure and information technology systems.

Section 6.5 Filings and Authorizations; HSR Act Filing.

(a) Seller and the Acquired Companies, on the one hand, and Buyer, on the other hand, shall file, as soon as reasonably practicable, all necessary registrations and filings, including, but not limited to, filings under the HSR Act or similar Law or regulation of any Governmental Entity, and will thereafter provide any additional or supplemental information requested by any Governmental Entity.

(b) Seller and the Acquired Companies, on the one hand, and Buyer, on the other hand, shall file or cause to be filed, as soon as reasonably practicable, with the applicable Governmental Entities all necessary filings in connection with the Seller Required Approvals and the Buyer Required Approvals, and will thereafter provide such Governmental Entities with any additional or supplemental information or filings requested by such Governmental Entities.

(c) Each of Buyer and Seller further agrees that it will, and will cause its Affiliates to, comply with any applicable post-Closing notification or requirements of any antitrust, trade competition, investment control reporting or similar Law or regulation of any Governmental Entity with competent jurisdiction. Each of Buyer and Seller agrees to cooperate with and promptly to consult with, to provide any reasonably available information with respect to, and to provide, subject to appropriate confidentiality provisions, copies of all presentations and filings to any Governmental Entity to the other party or its counsel.

(d) In addition to the agreements set forth in Sections 6.5(a) through 6.5(c) above, Buyer shall use commercially reasonable efforts to ensure that the consents, approvals, waivers or other authorizations from Governmental Entities, including clearance under the HSR Act and by FERC, are obtained as promptly as practicable. Notwithstanding anything to the contrary in this Agreement, under no circumstances will Buyer or its Affiliates (including, for this purpose, the Acquired

Companies) be required as a condition of such consents, approvals, waivers or other authorizations to divest, sell or hold separate any of its or its Affiliates’ (including, for this purpose, the Acquired Companies’) assets, businesses or properties, or otherwise agree to any restrictions or limitations (other than those applicable to all recipients of such consents, approvals, waivers or other authorizations) on the ongoing operations or businesses of Buyer and/or its Affiliates (including, for this purpose, the Acquired Companies) (any of the foregoing, a “Burdensome Condition”).

(e) Prior to Closing, Seller shall cause the applicable Acquired Company to elect to opt out of public utility regulation pursuant to Kansas Statutes Annotated 66-104(e).

Section 6.6 Replacement of Existing Credit and Other Seller Support. Prior to the Closing Date, Seller and Buyer shall cooperate and Buyer shall use commercially reasonable efforts to terminate, or cause Buyer or, if it is able to do so, one of its Affiliates to be substituted in all respects for Seller and any of its Affiliates in respect of, all obligations of Seller or any of its Affiliates under the Existing Credit Support set forth in Section 4.18(a) of the Seller Disclosure Schedule and any Existing Credit Support issued or procured in accordance with Section 6.3. With respect to any Existing Credit Support described in the immediately foregoing sentence that remains outstanding after the Closing Date (the “Outstanding Credit Support”), (a) Buyer shall continue to use commercially reasonable efforts to terminate, or cause Buyer or, if it is able to do so, one of its Affiliates to be substituted in all respects for Seller and any of its Affiliates in respect of, all obligations of Seller or any of its Affiliates under such Outstanding Credit Support, (b) subject to Seller’s indemnification obligations under Article 9, Buyer shall, and shall cause the Acquired Companies to, jointly and severally, indemnify and hold harmless Seller and its Affiliates for any Losses arising from such Outstanding Credit Support, including, without limitation, for any amounts owed to developers pursuant to the Contracts listed in Section 6.6 of the Seller Disclosure Schedule, and (c) Buyer shall not permit any Acquired Company to (i) renew or extend the term of or (ii) increase its obligations under, or transfer to another third party, any loan, lease, Contract or other obligation for which Seller or any of its Affiliates is or would reasonably be expected to be liable under such Outstanding Credit Support. After the Closing, to the extent that Seller or any of its Affiliates has performance obligations under any Outstanding Credit Support, Buyer will use commercially reasonable efforts to (x) perform such obligations on behalf of Seller or any of its Affiliates or (y) otherwise take such action as reasonably requested by Seller so as to put Seller or any of its Affiliates in the same position as if Buyer, and not Seller or any of its Affiliates, had performed or were performing such obligations.

Section 6.7 Use of Corporate Name. Within five (5) Business Days after the Closing Date, Buyer shall cause the Target Company, as well as any other Acquired Company (if applicable and to the extent the following required actions would be solely within Buyer’s control using commercially reasonable efforts), to change its name to a name that does not include “Deere,” “John Deere,” “JD,” “John Deere Renewables,” “John Deere Wind Energy,” “John Deere Credit,” or “Deere & Company” or any portion, variation, or derivative thereof or any name or mark confusingly similar

thereto (the “Seller Names and Marks”), to amend its certificate of formation (or equivalent organization document and any d/b/a or assumed name), as applicable, to remove any reference to the Seller Names and Marks, and to provide evidence of such change and amendment to Seller. Promptly following the Closing, and in any event no later than sixty (60) days after the Closing Date, Buyer shall cause each of the Acquired Companies to (i) cease all use of the Seller Names and Marks and any trademarks, service marks, names, corporate names, trade names, domain names, logos, slogans, trade dress, design rights, or other similar designations of source or origin containing any Seller Name and Mark, and (ii) cease to hold themselves out as having any affiliation with Seller or any of its Affiliates. In furtherance thereof, as soon as practicable, but in no event later than sixty (60) days following the Closing Date, Buyer shall cause each of the Acquired Companies to remove, strike over, or otherwise obliterate all Seller Names and Marks from all assets and other materials owned by the Acquired Companies, including any equipment, machinery, vehicles, business cards, schedules, stationery, packaging materials, displays, signs, promotional materials, manuals, forms, websites, email, computer software, and other materials and systems. Any use by the Acquired Companies of any of the Seller Names and Marks as permitted in this Section 6.7 shall be in a form and manner, and with standards of quality, of that in effect for the Seller Names and Marks as of the Closing Date and shall not reflect negatively on such Seller Names and Marks or on Seller or its Affiliates. Seller shall have the right to terminate the foregoing license, effective immediately, if Buyer or its Affiliates fail to comply with the foregoing terms and conditions or otherwise fail to comply with any reasonable direction of Seller in relation to the use of the Seller Names and Marks and fail to cure such failure to comply within thirty (30) days following receipt from Seller of written notice of such failure to comply. Buyer shall indemnify and hold harmless the Seller Indemnified Parties for any Losses arising from or relating to the use by Buyer or any of its Affiliates of the Seller Names and Marks pursuant to this Section 6.7.

Section 6.8 Employees and Employee Benefits.

(a) Prior to the Closing Date, Seller or its Affiliates shall transfer the employment of each Designated Employee employed by Seller or any of its Affiliates (other than the Acquired Companies) to the Target Company. Prior to Closing, Seller (i) will provide access, as reasonably requested by Buyer, to the Designated Employees for purposes of Buyer’s determination whether to make post-Closing offers of employment to such Designated Employees, but (ii) will not provide the written notice, which is contemplated in the retention agreements previously granted by the Target Company as a condition to receiving retention bonuses, to any Designated Employee who has received an Employment Offer (i.e., notice that the Designated Employee’s services are no longer needed by Seller or its Affiliates) (the “Termination Notice”), unless and until (x) such Designated Employee has notified Seller that he or she will not be accepting such offer and (y) Seller has determined, in good faith, that the termination of such Designated Employee’s employment prior to the Closing will not prevent Seller from fulfilling its obligations under this Agreement, including, without limitation, those set forth in Section 6.3. The foregoing notwithstanding, Seller will not provide a Termination Notice to any of the Designated Employees listed on Section 6.8(a) of the Seller Disclosure Schedule, with an effective date earlier than the Closing Date. For

purposes of this Agreement, an “Employment Offer” shall mean an offer of “at will” employment that (1) sets forth the material terms and conditions of employment with Buyer or its Affiliates, and (2) is made by Buyer or its Affiliates no later than September 30, 2010. Buyer and Seller shall coordinate regarding the timing for the making of Employment Offers. In that regard, it is the present intention of Buyer and Seller that Employment Offers will be made by Buyer during the last two (2) weeks of September, and that employees will be given at least two (2) weeks during which to accept any offer so extended. Effective no later than the Closing Date, Seller or its Affiliates shall terminate the employment of all Company Employees employed by any of the Acquired Companies that are not Transferred Employees.

(b) As of the Closing Date, Seller shall cause the Acquired Companies to cease being participating employers under each Employee Benefit Plan. Seller shall or shall cause the Acquired Companies to notify Designated Employees in accordance with applicable Law that, as of the Closing Date, Designated Employees shall cease to accrue any further benefits as active participants and shall have no rights to continue as active participants in the Employee Benefit Plans (without derogation of their rights as vested, terminated participants). Seller shall cause all Transferred Employees who are not vested in benefits accrued under the Employee Benefit Plans listed in Section 6.8(b) of the Seller Disclosure Schedule in which they participate to become fully vested as of the Closing Date, and Buyer shall credit Transferred Employees’ service with Seller under Buyer’s comparable plans to such Employee Benefit Plans in which they are eligible to participate for purposes of eligibility and vesting (but not benefit accrual) following the Closing Date.

(c) Seller shall retain sole responsibility and liability, and shall hold harmless the Buyer Indemnified Parties from and against any and all Losses incurred by any Buyer Indemnified Party, by reason of any (i) obligations with respect to Business Employees for all periods prior to Closing, including, without limitation, for amounts due and owing under retention agreements previously executed by Seller with such employees, (ii) except as expressly provided in subparagraph (d) hereof, obligations of any kind relating to the Employee Benefit Plans (whether relating to periods before, on or after the Closing Date), (iii) obligations of any kind relating to change of control payments, sale bonuses, retention payments, severance payments, termination payments and similar payments arising under agreements or arrangements with Seller or its Affiliates (including the Acquired Companies) in place on or prior to the Closing Date (whether relating to periods before, on or after the Closing Date) and (iv) incentive compensation earned or accrued by each Business Employee as of October 31, 2010 (including short and mid-term incentives for the fiscal year ending as of such date), which compensation Seller shall pay to such Business Employee in the ordinary course.

(d) Seller shall be responsible for all legally mandated continuation of health care coverage for all Business Employees and any of their covered dependents who experience a qualifying event on or before the Closing Date. Buyer shall be responsible for all legally mandated continuation of health care coverage for all Transferred Employees and their covered dependents who experience a qualifying event after the Closing Date.

(e) Without limiting the generality of Section 10.13, this Section 6.8 shall be binding upon and inure solely to the benefit of each of the parties to this Agreement, and nothing in this Section 6.8, expressed or implied, is intended to confer upon any other person any rights or remedies of any nature whatsoever under or by reason of this Section 6.8, and no provision of this Section 6.8 will (i) create any third party beneficiary rights in any current or former Business Employee or officer, director or individual independent contractor of the Acquired Companies in respect of continued employment (or resumed employment) or service or any other matter and (ii) be construed to establish or amend any compensation or benefit plan, agreement or arrangement.

Section 6.9 Transition Services. Prior to the Closing Date, Seller and Buyer shall cooperate and shall use their respective commercially reasonable efforts to agree on the services to be provided by Seller post-Closing pursuant to the Transition Services Agreement. The services to be provided by Seller thereunder shall be limited to information technology, accounting and financial services and such other services provided by Seller and its Affiliates (other than the Acquired Companies) during the twelve month period prior to the Closing, as reasonably requested by Buyer, all in a manner similar to those provided during such period by Seller or its Affiliates (other than the Acquired Companies) or employees retained by Seller or its Affiliates (other than the Acquired Companies) following the Closing, as well as office space and services related thereto. All services shall have the term set forth in the Transition Services Agreement, but, in no event, more than six (6) months commencing with the Closing Date. In connection with the provision of such services, the Transition Services Agreement shall provide for fees approximating Seller’s costs (including the costs of employees providing such services), plus five percent (5%).

Section 6.10 Intercompany Accounts. Prior to or at Closing, Seller shall, and shall cause its Affiliates to, settle (whether in the ordinary course of business or, in Seller’s or its Affiliates’ discretion, by way of capital contribution, dividend or otherwise) or otherwise cancel, all Seller Intercompany Debt and Target Company Intercompany Debt (other than that owed by an Acquired Company in the Partially-Owned Group), outstanding as of the Closing. Prior to or at Closing, Seller shall deliver to Buyer evidence of such settlement or cancellation of all such Seller Intercompany Debt and Target Company Intercompany Debt in such form and substance as is reasonably acceptable to Buyer. Prior to the Closing, Seller shall, and shall cause its Affiliates to, repay and discharge all Third-Party Debt other than the Third-Party Debt set forth in Section 4.18(b) of the Seller Disclosure Schedule. Prior to or at Closing, Seller shall deliver to Buyer evidence of such repayment and discharge of such Third-Party Debt (other than the Third-Party Debt set forth in Section 4.18(b) of the Seller Disclosure Schedule), if any, in such form and substance as is reasonably acceptable to Buyer.

Section 6.11 Commercially Reasonable Efforts. Upon the terms and subject to the conditions herein provided, except as otherwise provided in this Agreement, each of the parties hereto agrees to use commercially reasonable efforts to take or cause to be taken all action, to do or cause to be done, and to assist and cooperate with the other party hereto in doing, all things necessary, proper or advisable under applicable Laws and

regulations to consummate and make effective, in the most expeditious manner practicable, the transactions contemplated hereby, including, but not limited to, (a) the satisfaction of the conditions precedent to the obligations of any of the parties hereto, (b) the obtaining of consents, waivers or approvals of any third parties under the Material Contracts, (c) the defending of any lawsuits or other legal proceedings, whether judicial or administrative, challenging this Agreement or the performance of the obligations hereunder, and (d) the execution and delivery of such instruments, and the taking of such other actions as the other party hereto may reasonably require in order to carry out the intent of this Agreement. Notwithstanding anything to the contrary in this Agreement, the parties hereto acknowledge and agree that neither Seller nor Buyer shall have any obligation to pay any consideration or to offer to grant, or agree to, any financial or other accommodation in order to obtain any third-party consents, waivers and approvals.

Section 6.12 Tax Matters.

(a) Transfer Taxes. All Transfer Taxes arising out of or in connection with the transactions contemplated by this Agreement shall be borne equally by Seller and Buyer. Buyer shall prepare and file when due all necessary documentation and Tax Returns with respect to such Transfer Taxes. Buyer shall provide such documentation or Tax Returns to Seller for review and comment at least thirty (30) days prior to the due date for the filing of such documentation or Tax Returns. Buyer shall include, in the documentation or Tax Returns filed, all reasonable comments provided by Seller. Seller shall pay to Buyer its share of the Transfer Taxes reflected thereon on or prior to such filing due date. Buyer shall timely remit, or cause to be timely remitted, all Transfer Taxes. Buyer and Seller shall cooperate reasonably and in good faith in order to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

(b) Tax Returns. Except as otherwise provided in Section 6.12(a):

(i) Seller shall prepare and timely file, or cause to be prepared and timely filed, (A) all Tax Returns that are required to be filed by or with respect to the income, assets or operations of the Target Company and each Acquired Company comprising the Wholly-Owned Group for taxable years or periods ending on or before the Closing Date, and (B) all Tax Returns that are required to be filed by Seller with respect to the income, assets or operations of each Acquired Company comprising the Partially-Owned Group for taxable years or periods ending on or before the Closing Date. Seller shall timely remit, or cause to be timely remitted, all Taxes due in respect of such Tax Returns, but only to the extent any such Taxes exceed the accruals and reserves for such Taxes included as Current Liabilities for purposes of determining the Closing Net Working Capital.

(ii) To the extent within the power of Seller, Buyer or any of their Affiliates using commercially reasonable efforts, Seller shall prepare and timely file, or cause to be prepared and timely filed, all Tax Returns that are required to be filed by each Acquired Company comprising the Partially-Owned Group for taxable years or periods ending on or before the Closing Date.

(iii) Buyer shall prepare and timely file, or cause to be prepared and timely filed, all Tax Returns that are required to be filed by the Target Company and each Acquired Company comprising the Wholly-Owned Group for taxable years or periods beginning on or before, and ending after, the Closing Date. Buyer shall timely remit, or cause to be timely remitted, all Taxes due in respect of such Tax Returns. All such Tax Returns shall be prepared in a manner consistent with past practice. Not later than thirty (30) days prior to the due date for filing of each such Tax Return, Buyer shall provide Seller with a draft copy of such Tax Return for review and comment, and Buyer shall include, in the Tax Return filed, all reasonable comments provided by Seller with respect to any such draft copy not later than five (5) days prior to such due date.

(iv) To the extent within the power of Buyer or any of its Affiliates using commercially reasonable efforts, Buyer shall prepare and timely file, or cause to be prepared and timely filed, all Tax Returns that are required to be filed by each Acquired Company comprising the Partially-Owned Group for taxable years or periods beginning on or before, and ending after, the Closing Date. To the extent within the power of Buyer or any of its Affiliates using commercially reasonable efforts, Buyer shall timely remit, or cause to be timely remitted, all Taxes due in respect of such Tax Returns. All such Tax Returns shall be prepared in a manner consistent with past practice. Not later than thirty (30) days prior to the due date for filing of each such Tax Return, Buyer shall provide Seller with a draft copy of such Tax Return for review and comment, and Buyer shall include, in the Tax Return filed, all reasonable comments provided by Seller with respect to any such draft copy not later than five (5) days prior to such due date.

(v) Buyer shall not amend, refile or otherwise modify, or cause or permit to be amended, refiled or otherwise modified, any Tax Return filed by any Acquired Company for any taxable year or period beginning on or before the Closing Date.

(i) Upon the written request of Buyer setting forth in detail the computation of the amount owed, Seller shall pay to Buyer, no later than three (3) days prior to the due date for the applicable Tax Return, Seller’s Allocable Share of the Taxes for which Seller is liable pursuant to Section 6.12(c)(ii) but which are payable with any Tax Return to be filed by Buyer pursuant to Section 6.12(b), but only to the extent any such Taxes exceed the accruals and reserves for such Taxes included as Current Liabilities for purposes of determining the Closing Net Working Capital.

(ii) Seller and Buyer shall apportion or allocate all Taxes of or with respect to an Acquired Company or the income, assets or operations of any Acquired Company for a taxable year or period beginning on or before, and ending after, the Closing Date between the period deemed to end at the close of the Closing Date and the period deemed to begin at the beginning of the day following the Closing Date on the basis of an interim closing of the books in accordance with Section 706 of the Code, if applicable, except that Taxes (such as real or personal property Taxes) imposed on a periodic basis shall be allocated on a daily basis.

(d) Assistance and Cooperation. After the Closing Date, (i) Buyer shall (and shall cause its Affiliates to) assist Seller in preparing any Tax Returns that Seller is responsible for preparing and filing in accordance with Section 6.12(b), (ii) Seller shall (and shall cause its Affiliates to) assist Buyer in preparing any Tax Returns that Buyer is responsible for preparing and filing in accordance with Section 6.12(b), and (iii) Buyer and Seller shall (and shall cause their respective Affiliates to) cooperate fully in preparing for any audits of, or disputes with any Governmental Entity regarding, any Tax Returns by or with respect to any Acquired Company or with respect to the income, assets or operations of any Acquired Company.

(e) Audits. Buyer and Seller shall notify the other Party regarding, and within ten (10) days after, the receipt by Buyer, Seller or any of their Affiliates (including the Acquired Companies) of notice of any inquiries, claims, assessments, audits or similar events with respect to (i) Taxes of or with respect to any Acquired Company or with respect to the income, assets or operations of any Acquired Company to the extent relating to any taxable year or period (or portion thereof) ending on or before the Closing Date, or (ii) any matter for which Seller may be obligated to provide indemnity pursuant to Section 9.1(a)(ix) (collectively, the “Seller Tax Claims”). Seller, at its sole cost and expense, shall control the resolution of any Seller Tax Claim with respect to Taxes of or with respect to any Acquired Company; provided, however, that Buyer and its Affiliates and counsel of their choice shall have the right to participate fully in all aspects of the prosecution or defense of such Seller Tax Claim (at Buyer’s cost and expense). Seller shall not settle or compromise any Seller Tax Claim that could adversely affect Buyer, the Acquired Companies, or any Affiliate of the foregoing without the prior written consent of Buyer (not to be unreasonably withheld, conditioned or delayed). For the avoidance of doubt, Seller shall control any such resolution with respect to Taxes of any Acquired Company comprising the Partially-Owned Group only to the extent within the power of Seller, Buyer or any of their Affiliates using commercially reasonable efforts.

(f) Carrybacks. Following the Closing Date, Buyer shall, and shall cause the Target Company and the Acquired Companies comprising the Wholly-Owned Group and, to the extent within the power of Buyer or any of its Affiliates using commercially reasonable efforts, the Acquired Companies comprising the Partially-Owned Group to, waive the right to carryback to any taxable year or period (or portion thereof) ending on or before the Closing Date any income tax losses, credits or similar items attributable to any Acquired Company.

(g) Final Base Purchase Price Allocation. As soon as practicable after the Closing Date, but in no event more than ninety (90) days after the Closing, Buyer shall deliver to Seller a statement (the “Allocation Schedule”) setting forth an allocation, for U.S. federal income tax purposes, of the Final Base Purchase Price, plus any liabilities deemed assumed for U.S. federal income tax purposes, among the Acquired Companies’ assets. If within thirty (30) days after Seller’s receipt of the Allocation Schedule, Seller notifies Buyer in writing that Seller objects to any allocation set forth in the Allocation Schedule, Buyer and Seller shall use reasonable best efforts to resolve such objection within twenty (20) days after such notification. In the event that Buyer and Seller are unable to resolve such objection within twenty (20) days after such notification, Buyer and Seller shall jointly retain the Auditor to resolve the disputed item. The Auditor shall resolve all disputed items submitted to it for resolution within twenty (20) days after submission, and such resolution shall be final, binding and conclusive on Buyer and Seller. Upon resolution of all disputed items by Buyer and Seller, or by the Auditor, the allocations reflected on the Allocation Schedule shall be adjusted to reflect such resolution (the Allocation Schedule, including all such adjustments, if any, the “Final Allocation Schedule”). The fees, costs and expenses of the Auditor in resolving any such dispute shall be borne by the party which, in the sole and conclusive judgment of the Auditor, is not the prevailing party, or if the Auditor determines that neither Buyer nor Seller is the prevailing party, then such fees, costs and expenses shall be borne equally by Buyer and Seller. To the extent permitted by Law, Buyer and Seller shall (i) timely file with each relevant Governmental Entity all forms and Tax Returns required to be filed in connection with the allocations set forth in the Final Allocation Schedule, (ii) be bound by such allocations for purposes of determining Taxes, (iii) prepare and file, and cause its respective Affiliates to prepare and file, its Tax Returns on a basis consistent with such allocations, and (iv) not take any position, or cause its respective Affiliates to take any position, inconsistent with such allocations on any Tax Return, in any audit or proceeding before any Governmental Entity or in any report made for Tax purposes; provided, however, that, notwithstanding anything in this Section 6.12(g) to the contrary, the parties shall be permitted to take a position inconsistent with that set forth in the Final Allocation Schedule if required to do so by a final and non-appealable decision, judgment, decree or other order by any court of competent jurisdiction. Adjustments pursuant to Section 2.5 and Section 2.6 and other post-Closing adjustments, if any, to the Final Base Purchase Price, and to any liabilities deemed assumed for U.S. federal income tax purposes, shall be allocated among the assets to which the adjustments relate.

(h) Tax Refunds. Upon receipt, Buyer shall promptly forward to Seller Buyer’s Allocable Share (at the time of such receipt) of any refund, rebate, abatement, reduction or other recovery (whether direct or indirect through a right of setoff or credit) of Taxes of or with respect to any Acquired Company or with respect to the income, assets or operations of any Acquired Company, and any interest received thereon, with respect to any taxable year or period (or portion thereof) ending on or before the Closing Date.

(i) 754 Elections. With respect to each Acquired Company comprising the Partially-Owned Group for which the election provided for under Section 754 of the Code is not already in effect, Seller shall obtain all consents and approvals

from all third parties reasonably anticipated to be required in order to make (or cause to be made) such election with respect to the taxable year of such Acquired Company in which the Closing Date occurs.

(j) Section 338(h)(10) Election. At Buyer’s option, Seller and Buyer shall join in making an election under Section 338(h)(10) of the Code (and any corresponding elections under state tax law) on Form 8023 or in such other manner as may be required by rule or regulation of the IRS, with respect to the acquisition of JDWE, LLC. Buyer will prepare and file the forms necessary for such election and will provide such forms to Seller at least sixty (60) days prior to the due date of filing. Seller shall deliver to Buyer at least thirty (30) days prior to the due date of filing such completed forms as are required to be filed under Section 338(h)(10) of the Code (and analogous provisions of state tax law).

Section 6.13 Pending Actions. Following the Closing, except with respect to Taxes, Buyer shall have exclusive authority and control over the investigation, prosecution, defense and appeal of all of the Buyer Actions, provided that Buyer shall not consent to the entry of judgment or enter into any settlement with respect to a Buyer Action without the prior written consent of the Seller Indemnified Parties that are parties to such Buyer Action (not to be unreasonably withheld, delayed or conditioned) unless the judgment or proposed settlement involves (a) only the payment of money, (b) does not impose an injunction or other equitable relief upon the Seller Indemnified Parties and (c) includes as a term thereof the release of the Seller Indemnified Parties from all liability with respect to such Buyer Action. As soon as practicable following the Closing, Buyer shall, and shall cause each of the Acquired Companies to, use its commercially reasonable efforts to have any Seller Indemnified Parties removed as parties to any Buyer Action in which they are named parties as soon as is reasonably practicable. From and after the Closing, Buyer agrees to indemnify and hold harmless the Seller Indemnified Parties against any and all obligations, penalties, damages, judgments, settlements, claims, payments, fines, interest, costs and expenses, demands, assessments, liabilities and awards incurred by the Seller Indemnified Parties arising or resulting from, or relating to, any Buyer Action, except for any such obligations, penalties, damages, judgments, settlements, claims, payments, fines, interest, costs and expenses, demands, assessments, liabilities or awards arising or resulting from, or relating to, any fraud or willful misconduct by any such Seller Indemnified Party.

Section 6.14 Post-Closing Access; Preservation of Records.

(a) From and after the Closing, Seller will make or cause to be made available to Buyer and its Representatives all books, records and documents of Seller and its Affiliates not transferred to Buyer and relating to the Business (and the reasonable assistance of personnel responsible for such books, records and documents) during regular business hours; provided, however, that access to such books, records, documents and employees will not unreasonably interfere with the normal business operations of Seller and its Affiliates and the reasonable out-of-pocket expenses of Seller and its Affiliates incurred in connection therewith will be paid by Buyer. Seller will, and will cause its Affiliates to, use commercially reasonable efforts to maintain and preserve all such books, records and other documents for seven (7) years after the Closing Date.

(b) Following the Closing and subject to applicable Law, Buyer will, and will cause its Affiliates to, make or cause to be made available to Seller and its Representatives all books, records and documents in connection with any matters relating to the conduct of the Business prior to the Closing, and to its personnel having knowledge of the whereabouts and/or contents of such books, records and documents as requested by Seller for any reasonable purpose related to Seller’s ownership of the Acquired Companies or operation of the Business; provided, however, that access to such books, records, documents and employees will not unreasonably interfere with the normal business operations of Buyer and its Affiliates and the reasonable out-of-pocket expenses of Buyer and its Affiliates incurred in connection therewith will be paid by Seller. Buyer will, and will cause its Affiliates to, use commercially reasonable efforts to maintain and preserve all such books, records and other documents for seven (7) years after the Closing Date.

Section 6.15 Further Assurances. In the event that at any time after the Closing any further action is necessary to carry out the purposes of this Agreement, the parties hereto shall take such further action (including the execution and delivery of such further documents and instruments) as a party hereto may reasonably request, all at the sole expense of the requesting party (unless the action requested should have been taken prior to the Closing, in which case the party that would have borne the expense of taking such action had it been taken prior to the Closing shall bear such expense).

Section 6.16 Contracts To Be Terminated. Buyer and Seller acknowledge and agree that the limited liability company operating agreement presently in effect relating to the Target Company, as well as the intercompany agreements identified on Section 6.16 of the Seller Disclosure Schedule, shall be deemed terminated as of the Closing Date and of no further force or effect.

Section 6.17 ITC Grant Proceeds. If and to the extent any ITC Grant Proceeds are received in respect of the Michigan Wind Projects, Buyer and Seller acknowledge and agree that such ITC Grant Proceeds shall be the sole property of Buyer and its Affiliates (including the Acquired Companies) and that Buyer and its Affiliates (including the Acquired Companies) shall be entitled to retain such ITC Grant Proceeds without any obligation to return or remit to Seller or any of its Affiliates, or reimburse Seller or any of its Affiliates for, such ITC Grant Proceeds. For the avoidance of doubt, Seller makes no representation regarding (i) the eligibility of any of the Development Projects for an ITC Grant or (ii) whether any Person is or may be eligible to apply for an ITC Grant, or receive ITC Grant Proceeds, in respect of any of the Development Projects.

Section 6.18 BETC Monetization Proceeds.

(a) Notwithstanding anything to the contrary in this Agreement, prior to the Closing Date, Seller or any of its Affiliates (including the Acquired Companies) shall be entitled, to the extent not prohibited by the Charter Documents of

the Oregon Project Entities, to (i) seek final certification under Or. Rev. Stat. Sections 469.185 to 469.225 (or any successors to such Sections) with respect to eligibility for a credit under Or. Rev. Stat. Section 315.354 (or any successor to such Section) in respect of any asset or assets owned by any Oregon Project Entity (an “Oregon BETC”), and (ii) transfer any Oregon BETC in exchange for a cash payment pursuant to Or. Rev. Stat. Section 469.206 (or any successor to such Section).

(b) Buyer acknowledges and agrees that any cash payment received by Seller or any of its Affiliates (including the Acquired Companies) pursuant to the procedures contemplated by the parties to the Charter Documents pursuant to the Charter Documents of the Oregon Project Entities in exchange for a transfer prior to the Closing Date of any Oregon BETC pursuant to Or. Rev. Stat. Section 469.206 (or any successor to such Section), irrespective of when such cash payment is received, shall be the sole property of Seller and its Affiliates (other than the Acquired Companies), and that Seller and its Affiliates (other than the Acquired Companies) shall be entitled to retain such cash payment without any obligation to return or remit to Buyer or the Acquired Companies, or reimburse Buyer or the Acquired Companies for, such cash payment. If Buyer or any of the Acquired Companies receives after the closing any cash payments in respect of any such pre-Closing transfer, then Buyer shall, and shall cause such Acquired Company to, forward such cash payment to Seller, and Buyer and Seller agree that Buyer, in forwarding, or causing to be forwarded, any such cash payment so received, is acting solely in the capacity of agent for Seller for purposes of collecting and remitting to Seller such cash payments to Seller in respect of such pre-Closing transfers.

(c) For each Oregon Project Entity that has not received, prior to the Closing Date, final certification or eligibility to participate in the relevant Oregon pass-through program under Or. Rev. Stat. Sections 469.185 to 469.225 (or any successors to such Sections) with respect to eligibility for an Oregon BETC (“Final Certification”), following the Closing Date, Buyer shall, and shall cause the applicable Oregon Project Entity, to the extent not prohibited by the Charter Documents of such Oregon Project Entity, to, at Seller’s sole cost and expense, continue to use commercially reasonable efforts to seek and receive such Final Certification or such pass-through eligibility. Once Final Certification or such pass-through eligibility is received, Buyer shall, and shall cause the applicable Oregon Project Entity, to the extent not prohibited by the Charter Documents of such Oregon Project Entity, to, comply with the provisions of Section 6.18(d).

(d) For each Oregon Project Entity that, prior to the Closing Date, has not transferred in exchange for a cash payment pursuant to Or. Rev. Stat. Section 469.206 (or any successor to such Section) (“Monetized”) any Oregon BETC, following the Closing Date, Buyer shall, and shall cause the applicable Oregon Project Entity, to the extent not prohibited by the Charter Documents of such Oregon Project Entity, to, at Seller’s sole cost and expense, use (or continue to use, as the case may be) commercially reasonable efforts to Monetize such Oregon BETC. Neither Buyer nor any of its Affiliates (including the Acquired Companies) shall have any liability for any failure to Monetize such Oregon BETCs in whole or in part. Within five (5) Business Days after the receipt by Buyer or any of its Affiliates (including the Oregon Project

Entities) of the proceeds of any Monetization of any Oregon BETC in accordance with this Section 6.18(d) and the applicable procedures set forth in the Charter Documents of the Oregon Project Entities, Buyer shall, or shall cause its applicable Affiliate to, remit to Seller, by wire transfer in immediately available funds to the account specified by Seller, an amount equal to the aggregate amount of such proceeds actually received by Buyer. All such proceeds received by Buyer or any of its Affiliates (including the Oregon Project Entities) shall, to the extent not prohibited by Law and the Charter Documents of the Oregon Project Entities, be treated by Buyer and all of its Affiliates for all Tax purposes as nontaxable receipts. In the event any such proceeds are treated as taxable income to Buyer or any of its Affiliates or the Oregon Project Entities, the amounts to be transferred to Seller pursuant to this Section 6.18(d) shall be the net after tax amounts distributed to Buyer (or its relevant Affiliate) from such Oregon Project Entity.

(e) If Seller so requests, Buyer shall, or shall cause the applicable Oregon Project Entity, to the extent not prohibited by the Charter Documents of such Oregon Project Entity, to, appoint Seller (or any of its Affiliates) to act as Buyer’s or the applicable Oregon Project Entity’s agent, at Seller’s sole cost and expense, in seeking such Final Certification and/or in Monetizing such Oregon BETC.

Section 6.19 Development Projects. Prior to the Closing, Seller shall use commercially reasonable efforts to permit the Michigan Wind 2 Project to commence construction to the extent required to maintain eligibility for the ITC Grant. Seller shall be deemed to have complied with this Section 6.19 and shall have no liability of any nature whatsoever in the event it is subsequently determined that the Michigan Wind 2 Project is not eligible for the ITC Grant for reasons relating to commencement of construction, if:

(a) Michigan Wind 2, LLC enters into a balance of plant construction agreement (or agreements with subcontractors for similar services), issues a notice to proceed thereunder such that physical work of a significant nature could commence on site before December 31, 2010 and, to the extent Closing has not yet occurred, that such physical work does commence prior to December 31, 2010; or

(b) the Target Company or one of the other Acquired Companies (i) enters into a binding letter agreement with Vestas-American Wind Technology, Inc. (“Vestas”), substantially in the form previously disclosed to Buyer (the “Written Proposal”), with such other changes as are deemed necessary or appropriate by the Target Company or such other Acquired Company, setting forth the terms and principles for entering into a definitive turbine supply agreement for the supply of fifty (50) V100-1.8MW wind turbines for the Michigan Wind 2 Project (the “Turbine Supply Agreement”), (ii) enters into the Turbine Supply Agreement no later than November 1, 2010, or such later date as shall be reasonably agreed upon by Buyer and Seller, and (iii) following the execution of the Turbine Supply Agreement, shall pay to Vestas an amount equal to (A) the amount set forth in the Written Proposal necessary to secure the delivery of (1) four (4) complete wind turbines or (2) completed nacelles and blade components with an aggregate value, together with clause (B), equal to at least five percent (5%) of the projected total value of the specified energy property for the Michigan Wind 2 Project, plus (B) five percent (5%) of the total contract price, representing the deposit (as such term is defined in the Written Proposal).

Seller agrees (x) to keep Buyer reasonably informed on the development of the Michigan Wind 2 Project, (y) to deliver copies of drafts of the balance of plant contract (or equivalent subcontracts) and the Turbine Supply Agreement and related agreements with the counterparties of such contracts as such drafts become available to Seller, and (z) not to enter into any such balance of plant contract, or the Turbine Supply Agreement, and not to agree to any changes to the Written Proposal, without the consent of Buyer, which shall not be unreasonably withheld, conditioned or delayed. For the avoidance of doubt, any payment made pursuant to this Section 6.19 shall be taken into account when calculating Aggregate Interim Capital Expenditures For Development Projects in accordance with Section 2.4.

Section 6.20 Cash Management. From the date hereof through the Closing, Seller and its Affiliates (other than the Acquired Companies) shall continue to provide cash management services to the Acquired Companies in a manner consistent with past practice. Accordingly, at Closing, the Acquired Companies shall have a zero cash balance.

Section 6.21 Title Insurance Policies. With respect to each operating project for which Seller has not as of the date of this Agreement made available to Buyer a title insurance policy, prior to Closing Seller shall, and shall cause the Acquired Companies to, use commercially reasonable efforts to cooperate with Buyer in connection with Buyer’s efforts to obtain an ALTA 2006 form title insurance commitment and/or title insurance policy issued by a national title insurance company reasonably acceptable to Buyer. Buyer and Seller shall be equally responsible for the costs and expenses incurred by Buyer prior to the Closing Date in connection with obtaining such title insurance commitments and/or title insurance policies. For the avoidance of doubt, Buyer and Seller acknowledge that receipt of the foregoing shall not be a condition to Closing.

Section 6.22 Exclusivity. Seller shall not take, nor shall it permit any of its Affiliates (or authorize or permit any investment banker, financial advisor, attorney, accountant or other Person retained by or acting for or on behalf of Seller or its Affiliates) to take, directly or indirectly, any action to initiate, assist, solicit, receive, negotiate or encourage any offer or inquiry from any Person to reach any agreement or understanding (whether or not such agreement or understanding is absolute, revocable, contingent or conditional) for, or otherwise attempt to consummate, the sale, transfer or other disposition of any of the Transferred Interests, any of the membership interests (or other ownership interests) in the Acquired Companies or the Acquired Companies to any Person other than Buyer or its Affiliates or any material portion of the assets or properties of any of the Acquired Companies, in each case whether by merger, sale of membership interests (or other ownership interests), reorganization, recapitalization, joint venture, sale of assets or otherwise. If Seller (or any such Person acting for or on Seller’s behalf) receives from any Person (other than Buyer) any offer referred to above, Seller shall promptly, orally or in writing, advise Buyer of such offer but shall not be obliged to disclose the identity of the Person making such offer.

Section 6.23 Insurance Policies.

(a) During the period from the date hereof until the Closing Date, Seller shall maintain, or cause to be maintained, the Insurance Policies in effect, except for changes made in the ordinary course of business regarding policies with respect to which the Acquired Companies are not the primary beneficiaries. From and after the Closing, Seller shall use commercially reasonable efforts to assist the Buyer and the Acquired Companies in making any claims against Insurance Policies not held by the Target Company for events and/or acts occurring prior to the Closing that may be covered by such Insurance Policies. Upon receiving notice from Buyer or the Acquired Companies of a claim for an event or act occurring prior to the Closing that may be covered by such Insurance Policies, Seller shall administer such claim in the ordinary course; provided, that Seller shall in no way be responsible or liable for any denial of coverage for any reason. As of the Closing Date, the insurance policies for property casualty held by Target Company shall include all of the Acquired Companies as named insureds.

(b) In the event that between the date of this Agreement and the Closing Date, any assets (other than immaterial assets) of the Business (i) have suffered property damage (ordinary wear and tear excepted) or are subject to eminent domain or condemnation proceedings, or (ii) are lost, in each of clauses (i) and (ii) other than in the ordinary course of business consistent with past practice and Prudent Industry Practice, Seller shall notify Buyer reasonably promptly in writing upon its becoming aware of such event. Seller shall, or shall cause its Affiliates to, either (i) prior to the Closing, use any insurance recoveries or other proceeds actually received by Seller or its Affiliates in respect of such damage, regardless of materiality, by property damage, eminent domain, condemnation proceedings or loss to repair, rebuild or replace the portion of the assets damaged or lost prior to the Closing, or (ii) (x) to the extent of any insurance recoveries or other proceeds actually received prior to the Closing and not used to repair, rebuild or replace such portion of assets, hold such insurance recoveries or other proceeds in trust for Buyer and, at the Closing, assign all of Seller’s or Seller’s Affiliates’, as applicable, right, title, and interest in and to such insurance recoveries or other proceeds to Buyer in compensation for such damage or loss, or (y) to the extent of any insurance recoveries or other proceeds yet to be received, use commercially reasonable efforts to diligently pursue any and all claims related thereto and assign all of Seller’s or Seller’s Affiliates’, as applicable, right, title, and interest to receive and collect such insurance recoveries or other proceeds upon payment thereof. For the avoidance of doubt, notwithstanding anything to the contrary contained herein, this Section 6.23(b) shall survive the Closing solely to the extent any such lost or damaged assets exist, and then only until the applicable insurance recoveries or other claim proceeds are received or denied.

Section 6.24 Books and Records. At the Closing or within thirty (30) days thereafter, Seller shall provide to Buyer the Books and Records not already in the possession of the Acquired Companies. Seller may retain one (1) copy of any such Books and Records for archival purposes.

Section 6.25 Mountain Home Claim Insurance Proceeds. In the event that Buyer or any Acquired Company receives any insurance proceeds under any insurance policy of any Acquired Company in effect as of the Closing Date in respect of the “Mountain Home” claim described in Section 4.15 of the Seller Disclosure Schedule, Buyer shall, and shall cause such Acquired Company to, promptly deliver such proceeds to Seller.

Section 6.26 Texas PURPA Litigation.

(a) During the period between the date hereof and the Closing Date, Seller shall not, and shall cause its Affiliates not to, settle or otherwise reach a compromise with respect to, or enter into an agreement to settle or compromise, any proceedings involved in the Texas PURPA Litigation without Buyer’s prior written consent, which consent may not be unreasonably withheld, conditioned or delayed.

(b) From and after the Closing Date, Buyer shall control, at its sole cost and expense, the proceedings involved in the Texas PURPA Litigation and shall use commercially reasonable efforts to continue litigating the proceedings involved in the Texas PURPA Litigation as it deems appropriate; provided, however, that in the event Buyer reasonably determines that continuing to proceed with the litigation of any of the proceedings involved in the Texas PURPA Litigation is not commercially reasonable, Buyer (i) may abandon such proceedings involved in the Texas PURPA Litigation upon prior written notice to Seller and (ii) shall have no further obligation to litigate such proceedings involved in the Texas PURPA Litigation. Buyer shall be permitted, in its sole discretion and at its sole cost and expense, to engage in discussions regarding, and enter into an agreement providing for, a settlement of the proceedings involved in Texas PURPA Litigation without the prior written consent of Seller so long as such proposed settlement entitles the Texas Project Entities to receive from Southwestern Public Service Company more than $15,000,000, in the aggregate, as compensation for electricity provided to Southwestern Public Service Company by the Texas Project Entities prior to the Closing. If, however, the amount of compensation to be received, pursuant to any such settlement, by the Texas Project Entities from Southwestern Public Service Company for electricity provided to Southwestern Public Service Company by the Texas Project Entities prior to the Closing is less than $15,000,000, in the aggregate (the “TXQF Conditional Pre-Close Refund”), then Buyer may not enter into any agreement providing for such settlement without Seller’s prior written consent, which consent may not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, but except in the event of a settlement consisting solely of an increased price, rate or formula for electricity provided on a going forward basis, the parties acknowledge and agree that it shall be considered unreasonable for Seller to withhold consent from any settlement which provides a TXQF Conditional Pre-Close Refund amount that is calculated at a price, rate or formula which would be applied in substantially the same manner for electricity provided to Southwestern Public Service Company on a going forward basis under the settlement.

(c) Buyer and Seller hereby acknowledge and agree that any and all compensation that the Texas Project Entities are entitled to receive, as a result of any settlement or final resolution of the proceedings involved in the Texas PURPA Litigation, from Southwestern Public Service Company in respect of the electricity provided to Southwestern Public Service Company by the Texas Project Entities prior to the Closing (the “Pre-Closing Period Compensation”) belongs solely to, and is solely for the benefit of, Seller and shall not be considered to be part of the assets being acquired by Buyer by virtue of its acquisition of the Transferred Interests pursuant to this Agreement. In the event that following the Closing any Texas Project Entity or one of its Affiliates receives any such payments in respect of the Pre-Closing Period Compensation, Buyer shall cause such Texas Project Entity or its Affiliate to promptly deliver such received payments to Seller. In the event that any such settlement or final resolution of the proceedings involved in the Texas PURPA Litigation provides that all or any portion of the Pre-Closing Period Compensation shall be paid by Southwestern Public Service Company as part of its payments to the Texas Project Entities for the electricity provided to Southwestern Public Service Company by the Texas Project Entities from and after the Closing, the parties shall reasonably cooperate in good faith to agree upon allocation of such payments in order that Seller receives the portion of such payments attributable to the Pre-Closing Period Compensation.

(d) Buyer and Seller hereby acknowledge and agree that any and all compensation that the Texas Project Entities or their Affiliates are entitled to receive, as a result of any settlement or final resolution of the proceedings involved in the Texas PURPA Litigation, from Southwestern Public Service Company in respect of the electricity provided to Southwestern Public Service Company by the Texas Project Entities from and after the Closing shall belong to, and be solely for the benefit of, the applicable Texas Project Entities, as Affiliates of Buyer.

ARTICLE VII

CONDITIONS OF PURCHASE

Section 7.1 Conditions to Each Party’s Obligations.

The obligations of each party hereto to effect the Closing shall be subject to the satisfaction on and as of the Closing Date of each of the following conditions, any or all of which may be waived, in whole or in part, to the extent permitted by applicable Law:

(a) Filings; Waiting Periods. The waiting period applicable to the purchase and sale of the Transferred Interests under the HSR Act shall have been terminated or shall have expired and no Burdensome Condition shall have been imposed in connection therewith.

(b) Regulatory Approvals. The Buyer Required Approvals and the Seller Required Approvals shall have been obtained and become Final Orders, and such Final Orders shall not have imposed any Burdensome Conditions.

(c) No Injunction. No temporary restraining order, preliminary or permanent injunction, cease and desist order or other legal restraint or prohibition of any Governmental Entity preventing the purchase and sale of the Transferred Interests contemplated hereby or the consummation of the transactions to be effected by Buyer at the Closing shall be in effect.

Section 7.2 Conditions to Obligations of Buyer.

The obligations of Buyer to effect the Closing shall be subject to the satisfaction (or waiver, in whole or in part, to the extent permitted by applicable Law, by Buyer) on and as of the Closing Date of each of the following conditions:

(a) Representations and Warranties and Covenants of Seller.

(i) At the Closing, (A) the Seller Fundamental Representations and the representations and warranties of Seller in Section 4.6(b) as they relate to the Suzlon Agreements shall be true and correct in all material respects (provided that if such Seller Fundamental Representations or such representations and warranties in Section 4.6(b) are subject to a Material Adverse Effect or other materiality threshold, such Seller Fundamental Representations or such representations and warranties in Section 4.6(b) shall be true and correct in all respects) as though made at and as of the Closing Date (except that to the extent such Seller Fundamental Representations or such representations and warranties in Section 4.6(b) expressly relate to a specified date, such Seller Fundamental Representations or such representations and warranties in Section 4.6(b) shall be true as of such specified date), and (B) the representations and warranties of Seller set forth in this Agreement other than the Seller Fundamental Representations and the representations and warranties of Seller in Section 4.6(b) as they relate to the Suzlon Agreements shall be true and correct (without giving effect to any “materiality,” “material adverse effect,” or “Material Adverse Effect” qualifiers set forth therein) as though made at and as of the Closing Date (except that to the extent such representations and warranties expressly relate to a specified date, such representations and warranties shall be true as of such specified date), except to the extent that breaches thereof have not had, and would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect;

(ii) Seller shall have in all material respects performed all obligations and complied with all covenants and conditions required by this Agreement to be performed or complied with by it at or prior to the Closing (other than the obligations, covenants and conditions set forth in Section 6.12(i)); and

(iii) Seller shall have delivered to Buyer a certificate signed by an officer of Seller, dated as of the Closing Date, that the conditions set forth in Section 7.2(a)(i) and Section 7.2(a)(ii) have been satisfied.

(b) Deliverables. Seller shall have complied with its obligations contained in Section 2.3(b).

(c) No Material Adverse Effect. There shall not have occurred any Material Adverse Effect subsequent to the date hereof.

Section 7.3 Conditions to Obligations of Seller.

The obligations of Seller to effect the Closing shall be subject to satisfaction (or waiver, in whole or in part, to the extent permitted by applicable Law, by Seller) on and as of the Closing Date of each of the following conditions:

(a) Representations and Warranties and Covenants of Buyer.

(i) At the Closing, (A) the Buyer Fundamental Representations shall be true and correct in all material respects (provided that if such Buyer Fundamental Representation is subject to a materiality threshold, such Buyer Fundamental Representation shall be true and correct in all respects) as though made at and as of the Closing Date (except that to the extent such Buyer Fundamental Representations expressly relate to a specified date, such Buyer Fundamental Representation shall be true as of such specified date), and (B) the representations and warranties of Buyer set forth in this Agreement other than the Buyer Fundamental Representations shall be true and correct (without giving effect to any “materiality” or “material adverse effect” qualifiers set forth therein) as though made at and as of the Closing Date (except that to the extent such representations and warranties expressly relate to a specified date, such representations and warranties shall be true as of such specified date), except to the extent that breaches thereof have not had, and would not reasonably be expected to have, individually or in the aggregate, a material adverse effect on Buyer’s ability to consummate the transactions contemplated hereby;

(ii) Buyer shall have in all material respects performed all obligations and complied with all covenants and conditions required by this Agreement to be performed or complied with by it at or prior to the Closing; and

(iii) Buyer shall have delivered to Seller a certificate of Buyer signed by an officer of Buyer, dated as of the Closing Date, that the conditions set forth in Section 7.3(a)(i) and Section 7.3(a)(ii) have been satisfied.

(b) Deliverables. Buyer shall have complied with its obligations contained in Section 2.3(c).

(c) Letters of Credit. All letters of credit set forth on Section 4.18(a) of the Seller Disclosure Schedule shall have been terminated, or Seller and its Affiliates, as applicable, shall have obtained releases from the beneficiaries thereof (in form and in substance reasonably satisfactory to Seller or the applicable Affiliate), from any liability of Seller or its Affiliates under such Existing Credit Support.

ARTICLE VIII

TERMINATION

Section 8.1 Termination.

(a) Termination of Agreement. This Agreement may be terminated as follows:

(i) by mutual written consent of Buyer and Seller at any time prior to the Closing Date;

(ii) by the written notice of Buyer or Seller to the other party if the Closing shall not have occurred on or before January 31, 2011 (the “Outside Date”); provided, however, that the right to terminate this Agreement under this Section 8.1(a)(ii) shall not be available to any party whose failure to fulfill any obligation under this Agreement shall have been the cause of, or shall have resulted in, the failure of the Closing to occur on or prior to such date; provided further, that if as of January 31, 2011, all conditions set forth in Article VII shall have been satisfied or waived (excluding, for these purposes, those conditions that by their nature are to be satisfied by actions taken at the Closing, provided that such conditions are capable of being satisfied) other than the conditions set forth in Section 7.1(a), Section 7.1(b) or Section 7.1(c), then the Outside Date shall automatically be extended to March 31, 2011;

(iii) by the written notice of Buyer or Seller to the other party (provided that the terminating party is not then in material breach of any representation, warranty, covenant or other agreement contained herein) if there shall have been a material breach of any representation, warranty, covenant or other agreement contained herein on the part of the other party, which breach either (i) is not cured within thirty (30) days following written notice to the party committing such breach or (ii) by its nature, cannot be cured prior to the Outside Date; or

(iv) by written notice by Buyer to Seller or by Seller to Buyer (provided that the terminating party is not then in material breach of any representation, warranty, covenant or other agreement contained herein), if (i) any Governmental Entity, the consent of which is a condition to the obligations of the Seller and the Buyer to consummate the Closing, shall have determined not to grant its or their consent and all appeals of such determination shall have been taken and have been unsuccessful or any Burdensome Condition is imposed, (ii) one or more courts of competent, jurisdiction in the United States or any State shall have issued an order, judgment or decree permanently restraining, enjoining or otherwise prohibiting the Closing, and such order, judgment or decree shall have become final and nonappealable or (iii) any Law shall have been enacted by any Governmental Entity in the United States which prohibits the consummation of the Closing.

(b) Effect of Termination. In the event of termination of this Agreement by a party hereto pursuant to Section 8.1(a) hereof, written notice thereof shall forthwith be given by the terminating party to the other party hereto, and this Agreement shall thereupon terminate and become void and have no effect, and the transactions contemplated hereby shall be abandoned without further action by the parties hereto, except that the provisions of Sections 6.1, this 8.1(b), 10.1, 10.2, 10.3, 10.5, 10.6, 10.7, 10.8, 10.9, 10.11, 10.13 and 10.14 shall survive the termination of this Agreement; provided, however, that (i) such termination shall not relieve any party hereto of any liability for damages actually incurred or suffered by any other party as a result of any breach of this Agreement (other than for unintentional or non-willful breaches of representations, warranties and covenants, as to which no party shall be liable to any other party hereunder), and (ii) upon such termination, the provisions of the Confidentiality Agreement shall automatically be extended and remain in full force and effect without any further action by Seller or Buyer for the longer of (x) one year following such termination or (y) the remaining term under the Confidentiality Agreement.

ARTICLE IX

INDEMNIFICATION

Section 9.1 Obligations of Seller.

(a) From and after the Closing, Seller shall indemnify, defend and hold harmless Buyer and each of its Affiliates (including after the Closing, the Acquired Companies in the Wholly-Owned Group and the Acquired Companies in the Partially-Owned Group (but with respect to any such Acquired Company in the Partially-Owned Group, only to the extent of Buyer’s Allocable Share)) and the directors, managers, officers, members, employees, agents, representatives, successors and assigns of each of the foregoing Persons (collectively, the “Buyer Indemnified Parties”) from and against any and all Losses incurred by any Buyer Indemnified Party by reason of, arising out of, resulting from or relating to: (i) any inaccuracy or breach of any of the representations or warranties (in each case, when made) made by Seller in this Agreement or in any certificate delivered by Seller to Buyer in connection herewith provided, however, that in the case of any such representation or warranty that is limited by “material”, “materiality”, “Material Adverse Effect” or words of similar effect, the occurrence of a breach or inaccuracy of such representation or warranty and the amount of Losses shall be determined as if such “material”, “materiality”, “Material Adverse Effect” or words of similar effect were not included therein, (ii) any breach or nonperformance of any of the covenants or agreements of Seller contained in this Agreement or in any certificate delivered by Seller to Buyer in connection herewith, (iii) any liability for Taxes of or with respect to any Acquired Company for any taxable year or period (or portion thereof) that ends on or before the Closing Date, but only to the extent of Buyer’s or its Affiliate’s Allocable Share of such Taxes, (iv) any liability for Taxes of Seller or any of its Affiliates for any taxable year or period (or portion thereof) that ends on or before the Closing Date to the extent such Taxes are collected from the Acquired Companies (x) as a result of the provisions of Treasury Regulations Section

1.1502-6 or the analogous provisions of any Law or (y) by Contract, (v) any “recapture,” within the meaning of the guidance issued by the U.S. Treasury Department under Section 1603 of Division B of the American Recovery and Reinvestment Act of 2009, P.L. 111-5, of all or part of the ITC Grant Proceeds received with respect to any application submitted by an Acquired Company prior to the Closing Date, but only if such recapture solely and directly results from an action taken by Seller; provided, however, that the Buyer Indemnified Parties shall not be entitled to be indemnified, defended or held harmless from or against any Losses incurred by any Buyer Indemnified Party by reason of, arising out of, resulting from or relating to any such recapture if (x) any representation or warranty made by Buyer in Section 5.11 was, as of the Closing, inaccurate in any respect or (y) such recapture would not have occurred had any rights of Buyer or any of its assigns under this Agreement not been assigned, in whole or in part, to any Person, (vi) any increase in the liability of Buyer or any of its Affiliates for Taxes by reason of, arising out of, resulting from or relating to Buyer or its Affiliate’s Allocable Share of the increase in U.S. federal and state taxable income or decrease in taxable loss with respect to any Acquired Company comprising the Partially-Owned Group for which the election provided for under Section 754 of the Code is not in effect with respect to the taxable year of such Acquired Company in which the Closing Date occurs, but only to the extent such liability directly and solely results from Seller’s failure to obtain all consents and approvals from all third parties required in order to make (or cause to be made) such election with respect to such Acquired Company, (vii) any liability for Taxes of Buyer or any of its Affiliates incurred solely as a result of the receipt of any payment by Buyer or any of its Affiliates and a payment made by Buyer or any of its Affiliates to Seller pursuant to Section 6.18, (viii) any liability for Taxes of Seller or any of its Affiliates (other than the Acquired Companies) imposed on Buyer as a successor or transferee pursuant to Tex. Tax Code § 111.020, Or. Rev. Stat. § 305.330, Minn. Stat. § 270C.57, or Mich. Comp. Laws Ann. § 205.27a, (ix) any net increase in liability for Taxes, or net decrease in taxable loss, in either case in the aggregate for Buyer and its Affiliates (including the Acquired Companies) by reason of, arising out of, resulting from or relating to any Final Determination (taking into account all adjustments attributable to such Final Determination) that Buyer, Seller or any of their Affiliates is not entitled to any or a portion of any Tax Credits or depreciation deductions claimed by it in a manner consistent with past practice with respect to an Acquired Company, except that the Buyer Indemnified Parties shall not be entitled to be indemnified, defended or held harmless pursuant to this clause (ix) if any such Final Determination is caused directly and solely by an action taken by Buyer or any of its Affiliates (including the Acquired Companies) (A) with respect to such Acquired Company’s structure or operations in existence as of the Closing Date (other than any action required by applicable Law, excluding any such action that would result in the inability to generate electricity with respect to the facility but only to the extent not at a level consistent with past practice) or (B) in an attempt by Buyer or any of its Affiliates (including the Acquired Companies) to acquire the interests of the other partners in such Acquired Company (other than any such acquisition which results in such Acquired Company being classified as disregarded as an entity separate from its owner for U.S. federal and state income Tax purposes), or (x) any Losses to which any Buyer Indemnified Party is entitled to indemnification pursuant to Section 9.1(a) of the Seller Disclosure Schedule.

(b) The obligation of Seller to indemnify the Buyer Indemnified Parties for Losses is subject to the following limitations: (i) Seller shall not be required to provide indemnification to any Buyer Indemnified Party pursuant to Section 9.1(a)(i) unless the aggregate amount of Losses incurred by all Buyer Indemnified Parties pursuant to such provision exceeds one-third percent (0.33%) of the Total Purchase Price (the “Basket”), and then the Buyer Indemnified Parties shall be entitled to indemnification only for the amount in excess of the Basket, and (ii) in no event shall the aggregate amount of such Losses for which Seller is obligated to indemnify the Buyer Indemnified Parties pursuant to Section 9.1(a)(i) exceed twenty percent (20%) of the Total Purchase Price (the “Maximum Amount”); provided, however, that the Basket shall not limit Seller’s indemnification of the Buyer Indemnified Parties with respect to any Losses by reason of, arising out of, resulting from or relating to breaches of any of the Seller Fundamental Representations or the representations and warranties of Seller in Section 4.6(b) as they relate to the Charter Documents of the Acquired Companies or the Suzlon Agreements; provided, further, that the Maximum Amount shall not limit Seller’s indemnification of the Buyer Indemnified Parties with respect to any Losses by reason of, arising out of, resulting from or relating to breaches of any of the Seller Fundamental Representations (other than Section 4.21) or the representations and warranties of Seller in Section 4.6(b) as they relate to the Charter Documents of the Acquired Companies. Notwithstanding anything to the contrary contained herein, the Basket and Maximum Amount shall not apply with respect to any Loss arising from or related to (and such Loss shall not be counted towards the Maximum Amount) (1) fraud, willful misconduct or intentional misrepresentation or (2) for the avoidance of doubt, any breach of any covenant or agreement hereunder.

(c) Notwithstanding anything in this Agreement to the contrary, the Buyer Indemnified Parties shall be entitled to be indemnified, defended and held harmless from and against any Losses incurred by any Buyer Indemnified Party by reason of, arising out of, resulting from or relating to any liability for Taxes included in the Current Liabilities only to the extent such Taxes exceed the accruals and reserves for such Taxes included as Current Liabilities for purposes of determining the Closing Net Working Capital, provided, however, that amounts for such Taxes not paid by Seller pursuant to Section 6.12(b)(i) and amounts for such Taxes paid by Buyer pursuant to Section 6.12(c)(i) shall be taken into account for purposes of making this calculation.

Section 9.2 Obligations of Buyer.

(a) From and after the Closing, Buyer shall indemnify, defend and hold harmless Seller and each of its Affiliates (other than the Acquired Companies) and the directors, managers, officers, members, employees, agents, representatives, successors and assigns of the foregoing Persons (collectively, the “Seller Indemnified Parties”) from and against any and all Losses incurred by any Seller Indemnified Party by reason of, arising out of, resulting from or relating to: (i) any inaccuracy or breach of any of the representations or warranties made by Buyer in this Agreement or in any certificate delivered by Buyer to Seller in connection herewith, (ii) any breach or nonperformance of any of the covenants or agreements of Buyer contained in this Agreement or in any certificate delivered by Buyer to Seller in connection herewith, (iii) any liability for

Taxes of or with respect to any Acquired Company for any taxable year or period (or portion thereof) that begins after the Closing Date, but only to the extent of Seller’s Allocable Share of such Taxes, (iv) any liability for Taxes included as Current Liabilities for purposes of determining the Closing Net Working Capital, or (v) any net increase in liability for Taxes directly and solely attributable to, or directly and solely resulting from, an election under Section 338(h)(10) of the Code (and any corresponding elections under state tax law) as contemplated by Section 6.12(j).

(b) The obligation of Buyer to indemnify the Seller Indemnified Parties for Losses is subject to the following limitations: (i) Buyer shall not be required to provide indemnification to any Seller Indemnified Party pursuant to Section 9.2(a)(i) unless the aggregate amount of Losses incurred by all Seller Indemnified Parties pursuant to such provision exceeds the Basket, and then the Seller Indemnified Parties shall be entitled to indemnification only for the amount in excess of the Basket; and (ii) in no event shall the aggregate amount of such Losses for which Buyer is obligated to indemnify the Seller Indemnified Parties pursuant to Section 9.2(a)(i) exceed the Maximum Amount; provided, however, that neither the Basket nor the Maximum Amount shall limit Buyer’s indemnification of the Seller Indemnified Parties with respect to any Losses by reason of, arising out of, resulting from or relating to breaches of any Buyer Fundamental Representations. Notwithstanding anything to the contrary contained herein, the Basket and Maximum Amount shall not apply with respect to any Loss arising from or related to (and such Loss shall not be counted towards the Maximum Amount) (1) fraud, willful misconduct or intentional misrepresentation or (2) for the avoidance of doubt, any breach of any covenant or agreement hereunder.

Section 9.3 Calculation of Losses; Final Purchase Price Adjustment; Mitigation.

(a) In calculating amounts payable to an Indemnified Party, the amount of the indemnified Losses shall not be duplicative of any other Loss for which an indemnification claim has been made and shall be computed net of (i) payments actually recovered by the Indemnified Party or any of its Affiliates under any insurance policy with respect to such Losses (in excess of reasonably foreseeable premium increases related thereto) and (ii) any prior or subsequent recovery by the Indemnified Party from any Person with respect to such Losses (net of out of pocket costs and expenses (including reasonable legal fees and expenses). For the avoidance of doubt, for any Losses incurred by any Buyer Indemnified Party with respect to any Acquired Company in the Partially-Owned Group, the indemnifiable portion of such Losses shall be limited to the proportion representing Buyer’s Allocable Share.

(b) All indemnity payments made pursuant to this Agreement shall, to the maximum extent permitted by applicable Law, be treated by all parties hereto (and all of their Affiliates) for all Tax purposes as adjustments to the Total Purchase Price.

(c) Notwithstanding anything to the contrary set forth herein, each of the parties hereto shall use commercially reasonable efforts to mitigate all Losses relating to a claim under this Article IX.

Section 9.4 Time for Claims. No claim for indemnification under Section 9.1(a)(i) or Section 9.2(a)(i) may be asserted after the Survival Expiration Date. If an Indemnified Party shall have, before the Survival Expiration Date, previously made a claim for such indemnification by delivering a notice (stating in reasonable detail the basis of such claim) to the applicable Indemnifying Party, then such claim and all Losses related thereto or arising therefrom will continue to survive until the claim for indemnification has been satisfied or otherwise resolved in accordance with this Agreement.

Section 9.5 Third-Party Claims. Except as otherwise provided in Section 6.12(e):

(a) In the event that any Action is commenced by a third party involving a claim for which an Indemnifying Party is required to provide indemnity hereunder (an “Asserted Liability”), the Indemnified Party shall promptly notify the Indemnifying Party in writing of such Asserted Liability (the “Claim Notice”); provided that no delay on the part of the Indemnified Party in giving any such Claim Notice shall relieve the Indemnifying Party of any indemnification obligation hereunder except to the extent that the Indemnifying Party is actually and materially prejudiced by such delay. The Indemnified Party shall provide to the Indemnifying Party copies of all non-ministerial notices and documents (including court papers) received by the Indemnified Party relating to the Asserted Liability.

(b) If the Indemnified Party shall give the Indemnifying Party a Claim Notice, the Indemnifying Party shall have the right (i) to employ counsel, at its own expense, reasonably acceptable to the Indemnified Party to defend any Asserted Liability, (ii) to control and conduct, subject to the Indemnifying Party’s obligations under Sections 9.5(c) and (d) below, any proceedings or negotiations in connection therewith and necessary or appropriate to defend the Indemnified Party and (iii) to take all other steps or proceedings, subject to the Indemnifying Party’s obligations under Sections 9.5(c) and (d) below, to settle or defend any such claims, unless such Asserted Liability is reasonably likely to (A) result in liabilities at least a majority of which, taken with other then existing Losses under this Article IX, would not be fully indemnified hereunder or (B) have a material adverse effect on the business or financial condition of the Indemnified Party after the Closing Date (taking into account any effect on the Tax liabilities or earnings of the Indemnified Party). Notwithstanding anything in this Agreement to the contrary, with respect to any Asserted Liability that (y) provides for injunctive, equitable or other non-monetary relief affecting the Indemnified Party or any of its Affiliates or Representatives or (z) relates to a claim brought by a Governmental Entity (other than claims in respect of Taxes), the Indemnified Party shall have the right to employ its own counsel (at the Indemnifying Party’s sole expense) to defend, settle and compromise such Asserted Liability, except that the Indemnifying Party shall not be obligated to indemnify the Indemnified Party for any monetary damages imposed directly or indirectly by such settlement or compromise if the Indemnifying Party’s prior written consent to such settlement or compromise has not been obtained (such consent not to be unreasonably withheld, conditioned or delayed). The Indemnifying Party shall notify the Indemnified Party in writing, as promptly as possible after receipt of a Claim Notice (but

in any case within twenty (20) days after receipt of a Claim Notice or such earlier time necessary to reasonably allow a timely response to the Asserted Liability (the “Indemnifying Notice Period”)) of its election to defend any such Asserted Liability. In the event that the Indemnifying Party assumes the defense as provided in this Section 9.5(b), the Indemnified Party shall have the right to participate in such defense (including with counsel of its choice), at its own expense, and the Indemnifying Party shall reasonably cooperate with the Indemnified Party in connection with such participation.

(c) If the Indemnifying Party assumes the defense of any Asserted Liability, it shall not settle such Asserted Liability (unless such settlement (i) imposes no burden, liability or relief other than monetary damages to be satisfied solely and fully by the Indemnifying Party, (ii) includes no finding or admission of any Violation of Law or Violation of any rights or interests of the Indemnified Party, (iii) will have no effect on any other Loss that may be incurred by the Indemnified Party and (iv) includes a complete and unconditional release of the Indemnified Party from and against any and all Losses relating to such Asserted Liability) without the consent of the Indemnified Party, which consent shall not be unreasonably withheld in the case of any settlement that (i) the Indemnifying Party recommends, (ii) by its terms obligates the Indemnifying Party to pay the full amount of Losses in connection with the Asserted Liability, and (iii) unconditionally releases the Indemnified Party and its Affiliates and Representatives completely from all Losses in connection with the Asserted Liability.

(d) The Indemnified Party may refuse to agree to any settlement, compromise or discharge of any Asserted Liability that (i) provides for injunctive, equitable or other non-monetary relief affecting the Indemnified Party or any of its Affiliates or Representatives, (ii) in the reasonable opinion of the Indemnified Party would materially adversely affect the Indemnified Party or its Affiliates or Representatives or (iii) includes a finding or admission of any Violation of applicable Law or any Violation of the rights of the Indemnified Party or any of its Affiliates or Representatives.

(e) If the Indemnifying Party does not deliver to the Indemnified Party written notice within the Indemnifying Notice Period that the Indemnifying Party will assume the defense of any Asserted Liability, (i) the Indemnified Party may defend against any such Asserted Liability in such manner as it may deem reasonably appropriate, at the cost of the Indemnifying Party (provided that the Indemnifying Party shall have the right to participate in such defense (including with counsel of its choice), at its own expense, and the Indemnified Party shall reasonably cooperate with the Indemnifying Party in connection with such participation), and (ii) the Indemnified Party may settle such Asserted Liability (provided that, the Indemnified Party shall not settle any such Asserted Liability without the prior written consent of the Indemnifying Party, which consent will not be unreasonably withheld or delayed).

(f) In all cases, the Indemnifying Party and the Indemnified Party (i) shall cooperate in the defense of Asserted Liabilities, (ii) shall keep each other informed of all material developments relating to or in connection with Asserted

Liabilities, (iii) agree to make available to each other, their counsel and other Representatives, all information and documents available to them which relate to any Asserted Liability and (iv) agree to render to each other such assistance and cooperation as may reasonably be required to ensure the proper and adequate defense of any such Asserted Liability.

Section 9.6 Exclusive Remedy. Except with respect to injunctive and other equitable relief expressly provided by this Agreement and for any action based on fraud, willful misconduct or intentional misrepresentation, the remedies provided in this Article IX shall be deemed the sole and exclusive remedies of the parties hereto, from and after the Closing Date, for any breach of or failure to perform or comply with any representation, warranty or covenant or other agreement contained in this Agreement, and the parties hereto each hereby waive to the extent permitted by applicable Law any other remedy, to which they or any other Person is entitled to indemnification hereunder may have at law or in equity with respect thereto. For the avoidance of doubt, no officer or other individual Representative of a party hereto shall have any personal liability to any Indemnified Party arising out of any certificate or other document executed by such officer or other individual and delivered to the other party.

Section 9.7 No Punitive Damages. Notwithstanding anything to the contrary contained herein, neither party hereto shall be liable to or otherwise responsible to any Indemnified Party for punitive damages (other than punitive damages awarded to a third party pursuant to a third party claim) that arise out of or relate to this Agreement or the performance or breach hereof or any liability assumed hereunder.

Section 9.8 No Right To Offset. Each party hereto agrees and acknowledges that neither party nor any other Indemnified Party shall be entitled to offset amounts payable to the other party or its Affiliates under the indemnification provisions of this Agreement against amounts payable to such party by the other party or its Affiliates now or in the future.

Section 9.9 Risk Allocation. The representations, warranties, covenants and agreements made herein, together with the indemnification provisions herein, are intended among other things to allocate the economic cost and the risks inherent in the transactions contemplated hereby between the parties, and, accordingly, a party shall be entitled to the indemnification or other remedies provided in this Agreement by reason of any breach of any such representation, warranty, covenant or agreement by another party notwithstanding whether any employee, representative or agent of the party seeking to enforce a remedy knew or had reason to know of such breach.

ARTICLE X

MISCELLANEOUS

Section 10.1 Assignment; Binding Effect. This Agreement and the rights hereunder are not assignable unless such assignment is consented to in writing by

both Buyer and Seller; provided that Buyer and its permitted assigns may at any time without the prior written consent of Seller: (a) assign, in whole or in part, its rights and obligations under this Agreement to one or more of its Affiliates or to any subsequent purchaser of the Target Company or any of the other Acquired Companies or of any material portion of the Target Company’s or any of the Acquired Company’s assets; provided that Buyer remains liable for the performance of Buyer’s obligations under this Agreement, and (b) assign its rights under this Agreement for collateral security purposes to any lenders providing financing to Buyer, the Target Company or any of the other Acquired Companies, such permitted assigns and/or any of their Affiliates. Subject to the preceding sentence, this Agreement and all the provisions hereof shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and permitted assigns.

Section 10.2 Choice of Law. THIS AGREEMENT SHALL BE GOVERNED BY AND INTERPRETED AND ENFORCED IN ACCORDANCE WITH THE SUBSTANTIVE LAWS OF THE STATE OF DELAWARE, WITHOUT GIVING EFFECT TO THE CONFLICTS OF LAW PROVISION OR RULE (WHETHER OF THE STATE OF DELAWARE OR ANY OTHER JURISDICTION) THAT WOULD CAUSE THE APPLICATION OF THE LAWS OF ANY JURISDICTION OTHER THAN THE STATE OF DELAWARE.

Section 10.3 Specific Performance; Consent to Jurisdiction.

(a) The parties agree and acknowledge that the failure to perform under this Agreement will be an actual, immediate and irreparable harm and injury and that the parties would not have any adequate remedy at law in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. Accordingly, it is agreed that, except where this Agreement is properly terminated in accordance with Article VIII, the parties shall be entitled to an injunction or injunctions to prevent breaches or threatened breaches of this Agreement and to specifically enforce the terms and provisions of this Agreement (including of Sections 5.8 and 6.2) and any other agreement or instrument executed in connection herewith. The parties further agree that they shall not object to, or take any position inconsistent with respect to, whether in a court of law or otherwise, the appropriateness of specific performance as a remedy for a breach of this Agreement or any such other agreement or instrument, any action or proceeding for any such remedy to be brought exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, only if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware), and each party waives any requirement for the securing or posting of any bond in connection with any such remedy. The parties further agree that by seeking the remedies provided for in this Section 10.3 a party shall not in any respect waive its right to seek any other form of relief that may be available to a party under this Agreement, including monetary damages.

(b) Each of the parties hereto (i) irrevocably consents to the service of the summons and complaint and any other process in any other action or

proceeding relating to the transactions contemplated by this Agreement, on behalf of itself or its property, by personal delivery of copies of such process to such party (and nothing in this Section 10.3 shall affect the right of any party to serve legal process in any other manner permitted by Law), (ii) irrevocably and unconditionally consents and submits itself and its property in any action or proceeding to the exclusive general jurisdiction of the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, only if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware) in the event any dispute arises out of this Agreement or the transactions contemplated by this Agreement, or for recognition and enforcement of any judgment in respect thereof, (iii) agrees that it will not attempt to deny or defeat such personal jurisdiction by motion or other request for leave from any such court, (iv) agrees that any actions or proceedings arising in connection with this Agreement or the transactions contemplated by this Agreement shall be brought, tried and determined only in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, only if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware), (v) waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same, and (vi) agrees that it will not bring any action relating to this Agreement or the transactions contemplated by this Agreement in any court other than the aforesaid courts. Each of Buyer and Seller agrees that a final judgment in any action or proceeding in such court as provided above shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by Law.

Section 10.4 Survival. The representations and warranties contained herein or in any certificate delivered in connection with this Agreement, except for the Seller Fundamental Representations, the Buyer Fundamental Representations, the representations and warranties of Seller in Section 4.6(b) as they relate to the Charter Documents and the Suzlon Agreements and the representations and warranties of Seller in Sections 4.11(a), 4.11(b)(iii), 4.11(b)(iv) and 4.12, shall survive the Closing and terminate on the date that is fifteen (15) months after the Closing Date (the “Survival Expiration Date”). The Seller Fundamental Representations (other than the representations and warranties contained in Sections 4.5, 4.8 and 4.21), and the Buyer Fundamental Representations (other than the representations and warranties contained in Section 5.11) shall survive the Closing indefinitely. The representations and warranties contained in Sections 4.5, 4.8 and 5.11 shall survive the Closing until ninety (90) days after the expiration of the applicable statute of limitations (including any extensions with respect thereto). The representations and warranties contained in Section 4.21 and the representations and warranties of Seller in Section 4.6(b) as they relate to the Suzlon Agreements shall survive the Closing and terminate on the date that is seven (7) years after the Closing Date. The representations and warranties contained in Sections
4.11(a), 4.11(b)(iii), 4.11(b)(iv) and 4.12 shall survive the Closing and terminate on the date that is three (3) years after the Closing Date. The representations and warranties of Seller in Section 4.6(b) as they relate to the Charter Documents of the Acquired Companies shall survive the Closing and terminate on the date that is four (4) years after the Closing Date.

All covenants and agreements contained herein which by their terms contemplate actions or impose obligations following the Closing shall survive the Closing and remain in full force and effect in accordance with their respective terms. To the extent that any covenants and agreements contained herein contemplate performance prior to Closing, such covenants and agreements shall terminate to such extent upon Closing; provided that the failure of such provisions to survive shall not prevent Buyer from making any claim for a breach, prior to the Closing, of such provisions. Notwithstanding anything in the foregoing to the contrary, any action based on fraud, willful misconduct or intentional misrepresentation shall survive the Closing indefinitely.

Section 10.5 Notices. All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given when delivered personally, when sent by confirmed cable, telecopy, telegram or facsimile, when sent by overnight courier service or when mailed by certified or registered mail, return receipt requested, with postage prepaid to the parties at the following addresses (or at such other address for a party as shall be specified by like notice):

If to Buyer, to:

Exelon Corporation

10 S. Dearborn

Chicago, IL 60603

Attention: General Counsel

Fax: (312) 394-8796

With copies to:

Foley & Lardner LLP

777 East Wisconsin Avenue

Milwaukee, WI 53202

Attention: James T. Tynion III

Jason W. Allen

Fax: (414) 297-4900

If to Seller, to:

Deere & Company

One John Deere Place

Moline, IL 61265

Attn: General Counsel

Fax: (309) 749-0085

With copies to:

Skadden, Arps, Slate, Meagher & Flom LLP

Four Times Square

New York, NY 10036 – 6522

Attn: David Friedman

Daniel Dusek

Fax: (212) 735-2000

Section 10.6 Headings. The headings contained in this Agreement are inserted for convenience only and shall not be considered in interpreting or construing any of the provisions contained in this Agreement.

Section 10.7 Fees and Expenses. Except as otherwise specified in this Agreement, each party hereto will bear its own costs and expenses (including investment advisory and legal fees and expenses) incurred in connection with this Agreement and the transactions contemplated hereby; provided that Buyer and Seller shall be equally responsible for all filing fees in connection with any required filings or submissions with FERC and under the HSR Act; provided, further, that Seller shall be solely responsible for all expenses of the Acquired Companies incurred in connection with the preparation, execution and consummation of this Agreement (and the transactions contemplated hereby), including fees and disbursements of attorneys, investment bankers, accountants and other professional advisors.

Section 10.8 Entire Agreement. This Agreement (including the Exhibits and Schedules hereto) and the Confidentiality Agreement (which shall survive and remain in effect until expiration or termination thereof in accordance with its terms and this Agreement), together constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior agreements and understandings between the parties with respect to such subject matter.

Section 10.9 Interpretation. When a reference is made to an Article, Section or Schedule, such reference shall be to an Article, Section or Schedule of or to this Agreement unless otherwise indicated. Whenever any of the words “include,” “includes” and “including” is used in this Agreement, it shall be deemed to be followed by the words “without limitation.” The phrase “Seller’s Knowledge” (or similar words) when used in a particular representation or warranty in this Agreement shall mean the actual knowledge of the individuals set forth in Section 10.9 of the Seller Disclosure Schedule after reasonable inquiry by such individual of those persons employed by Seller, its Affiliates or any Acquired Company whom such individuals reasonably believe in good faith to be the persons generally responsible for the information, facts or events with respect to which such representation or warranty applies. The phrase “Buyer’s Knowledge” (or similar words) shall mean the actual and imputed knowledge of the individuals set forth in Section 10.9 of Buyer Disclosure Schedule. References to this Agreement shall mean this Agreement as amended or supplemented, together with all Exhibits and Schedules attached or incorporated by reference.

Section 10.10 Disclosure. Any exception or qualification set forth in the Seller Disclosure Schedule or the Buyer Disclosure Schedule with respect to a particular representation, warranty or covenant contained in this Agreement shall be deemed to be an exception or qualification with respect to all other applicable representations, warranties and covenants contained in this Agreement by Seller or Buyer, respectively, to the extent that the applicability of such exception or qualification is reasonably apparent. The inclusion of information in any section of the Seller Disclosure Schedule or the Buyer Disclosure Schedule shall not be construed as an admission that such information is material to Seller, the Acquired Companies or Buyer. In addition, matters disclosed in the Seller Disclosure Schedule or the Buyer Disclosure Schedule are not necessarily limited to matters required by this Agreement to be disclosed in the Seller Disclosure Schedule or the Buyer Disclosure Schedule, respectively, and any such additional matters are set forth for informational purposes only and do not necessarily include other matters of a similar nature.

Section 10.11 Waiver and Amendment. Any provisions of this Agreement may be waived in writing at any time prior to Closing by Buyer or by Seller, and any of the provisions of this Agreement may be amended at any time by the mutual written agreement of Buyer and Seller.

Section 10.12 Counterparts; Facsimile Signatures. This Agreement may be executed in any number of counterparts (including by means of facsimile), each of which when executed, shall be deemed to be an original and all of which together will be deemed to be one and the same instrument binding upon all of the parties hereto notwithstanding the fact that all parties are not signatory to the original or the same counterpart. Delivery of an executed counterpart of a signature page to this Agreement by facsimile shall be effective as delivery of a manually executed counterpart of this Agreement.

Section 10.13 Third-Party Beneficiaries. This Agreement is for the sole benefit of (i) the parties hereto, (ii) their permitted assigns, and (iii) solely for the purposes of Article IX, the Seller Indemnified Parties and the Buyer Indemnified Parties. Nothing herein express or implied shall give or be construed to give to any other Person any legal or equitable rights hereunder.

Section 10.14 Severability. If any provision of this Agreement or the application of any such provision to any Person or circumstance shall be held invalid, illegal or unenforceable in any respect by a court of competent jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision hereof.

Section 10.15 Waiver.

(a) EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT, FROM AND AFTER THE CLOSING, SELLER HEREBY RELEASES AND FOREVER DISCHARGES THE ACQUIRED COMPANIES AND THEIR RESPECTIVE DIRECTORS, OFFICERS, EQUITY OWNERS, EMPLOYEES, AGENTS, REPRESENTATIVES, SUBSIDIARIES, AFFILIATED COMPANIES,

SUCCESSORS AND ASSIGNS OF AND FROM ANY AND ALL CLAIMS, DEMANDS, ACTIONS, CAUSES OF ACTION, LIABILITIES, DAMAGES, EXPENSES AND SUITS OF EVERY KIND, CHARACTER AND DESCRIPTION, KNOWN OR UNKNOWN, AT LAW OR IN EQUITY, WHICH SELLER MAY HAVE HAD AT ANY TIME HERETOFORE, MAY HAVE NOW OR MAY HAVE AT ANY TIME HEREAFTER, ARISING FROM, RELATING TO, RESULTING FROM OR IN ANY MANNER INCIDENTAL TO ANY AND EVERY MATTER, THING OR EVENT UP TO AND INCLUDING THE CLOSING, IN EACH CASE RELATING TO, (I) THE ACQUIRED COMPANIES, (II) THE TRANSFERRED INTERESTS OR ANY OTHER OWNERSHIP INTERESTS OF THE ACQUIRED COMPANIES IN OTHER ACQUIRED COMPANIES, OR (III) ANY INFORMATION PROVIDED BY THE ACQUIRED COMPANIES TO SELLER IN CONNECTION WITH OR RELATING TO THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT.

(b) EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT AND EXCEPT FOR ANY FRAUD OR WILLFUL MISCONDUCT ON THE PART OF ANY OF THE PERSONS BEING RELEASED PURSUANT TO THIS SECTION 10.15(b), FROM AND AFTER THE CLOSING, BUYER SHALL CAUSE EACH ACQUIRED COMPANY TO, RELEASE AND FOREVER DISCHARGE SELLER AND ITS AFFILIATES AND THEIR RESPECTIVE DIRECTORS, OFFICERS, EQUITY OWNERS, EMPLOYEES, AGENTS, REPRESENTATIVES, SUBSIDIARIES, AFFILIATED COMPANIES, SUCCESSORS AND ASSIGNS OF AND FROM ANY AND ALL CLAIMS, DEMANDS, ACTIONS, CAUSES OF ACTION, LIABILITIES, DAMAGES, EXPENSES AND SUITS OF EVERY KIND, CHARACTER AND DESCRIPTION, KNOWN OR UNKNOWN, AT LAW OR IN EQUITY, WHICH SUCH ACQUIRED COMPANY MAY HAVE HAD AT ANY TIME HERETOFORE, MAY HAVE NOW OR MAY HAVE AT ANY TIME HEREAFTER, ARISING FROM, RELATING TO, RESULTING FROM OR IN ANY MANNER INCIDENTAL TO ANY AND EVERY MATTER, THING OR EVENT UP TO AND INCLUDING THE CLOSING, IN EACH CASE RELATING TO, (I) THE OPERATION OF THE ACQUIRED COMPANIES, OR (II) THE TRANSFERRED INTERESTS OR ANY OTHER OWNERSHIP INTERESTS OF THE ACQUIRED COMPANIES IN OTHER ACQUIRED COMPANIES. FOR THE AVOIDANCE OF DOUBT, IN NO EVENT AND UNDER NO CIRCUMSTANCE SHALL THIS SECTION 10.15(b) IN ANY WAY LIMIT SELLER’S OBLIGATIONS UNDER THIS AGREEMENT, INCLUDING SELLER’S INDEMNIFICATION OBLIGATIONS UNDER ARTICLE IX, OR IN ANY WAY LIMIT BUYER’S OR THE BUYER INDEMNIFIED PARTY’S RIGHTS UNDER THIS AGREEMENT, INCLUDING THE RIGHT TO INDEMNIFICATION UNDER ARTICLE IX.

Section 10.16 Bulk Sales or Transfer Laws. Buyer acknowledges that Seller will not comply with the provision of any bulk sales or transfer Laws pursuant to Tex. Tax Code § 111.020, Or. Rev. Stat. § 305.330, Minn. Stat. § 270C.57, or Mich. Comp. Laws Ann. § 205.27a in connection with the transactions contemplated by this Agreement. Buyer hereby waives compliance by Seller with the provisions of the bulk sales or transfer Laws pursuant to Tex. Tax Code § 111.020, Or. Rev. Stat. § 305.330, Minn. Stat. § 270C.57, or Mich. Comp. Laws Ann. § 205.27a.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed the day and year first above written.


		DEERE & COMPANY

By:		/s/ James A. Israel
		Name: James A. Israel
		Title: President, John Deere Credit


		EXELON GENERATION COMPANY, LLC

By:		/s/ Christopher M. Crane
		Name: Christopher M. Crane
		Title: President

RULE 13A-14(A) CERT Filed by John W. Rowe for Exelon Corporation

Exhibit 31-1

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, John W. Rowe, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John W. Rowe

Chairman and Chief Executive Officer

(Principal Executive Officer)

Date: October 22, 2010

170

RULE 13A-14(A) CERT Filed by Matthew F. Hilzinger for Exelon Corporation

Exhibit 31-2

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Matthew F. Hilzinger, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: October 22, 2010

171

RULE 13A-14(A) CERT Filed by John W. Rowe for Exelon Generation Co., LLC

Exhibit 31-3

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, John W. Rowe, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John W. Rowe

Chairman

(Principal Executive Officer)

Date: October 22, 2010

172

RULE 13A-14(A) CERT Filed by Matthew F. Hilzinger for Exelon Generation Co., LLC

Exhibit 31-4

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Matthew F. Hilzinger, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Exelon Generation Company, LLC;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Matthew F. Hilzinger

(Principal Financial Officer)

Date: October 22, 2010

173

RULE 13A-14(A) CERT Filed by Frank M. Clark for Commonwealth Edison Company

Exhibit 31-5

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Frank M. Clark, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Frank M. Clark

Chairman and Chief Executive Officer

(Principal Executive Officer)

Date: October 22, 2010

174

RULE 13A-14(A) CERT Filed by Joseph R. Trpik, Jr for Commonwealth Edison Company

Exhibit 31-6

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Joseph R. Trpik, Jr., certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer

and Treasurer

(Principal Financial Officer)

Date: October 22, 2010

175

RULE 13A-14(A) CERT Filed by Denis P. O'Brien for PECO Energy Company

Exhibit 31-7

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Denis P. O’Brien, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Denis P. O’Brien

Chief Executive Officer and President

(Principal Executive Officer)

Date: October 22, 2010

176

RULE 13A-14(A) CERT Filed by Phillip S. Barnett for PECO Energy Company

Exhibit 31-8

CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES

AND EXCHANGE ACT OF 1934

I, Phillip S. Barnett, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Phillip S. Barnett

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: October 22, 2010

177

SECTION 1350 CERT Filed by John W. Rowe for Exelon Corporation

Exhibit 32-1

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Exelon Corporation for the quarterly period ended September 30, 2010, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

/s/ John W. Rowe

John W. Rowe

Chairman and Chief Executive Officer

Date: October 22, 2010

178

SECTION 1350 CERT Filed by Matthew F. Hilzinger for Exelon Corporation

Exhibit 32-2

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Date: October 22, 2010

179

SECTION 1350 CERT Filed by John W. Rowe for Exelon Generation Co., LLC

Exhibit 32-3

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended September 30, 2010, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

/s/ John W. Rowe

John W. Rowe

Chairman (Principal Executive Officer)

Date: October 22, 2010

180

SECTION 1350 CERT Filed by Matthew F. Hilzinger for Exelon Generation Co., LLC

Exhibit 32-4

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

(Principal Financial Officer)

Date: October 22, 2010

181

SECTION 1350 CERT Filed by Frank M. Clark for Commonwealth Edison Company

Exhibit 32-5

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of Commonwealth Edison Company for the quarterly period ended September 30, 2010, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

/s/ Frank M. Clark

Frank M. Clark

Chairman and Chief Executive Officer

Date: October 22, 2010

182

SECTION 1350 CERT Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

Exhibit 32-6

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Date: October 22, 2010

183

SECTION 1350 CERT Filed by Denis P. O'Brien for PECO Energy Company

Exhibit 32-7

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the quarterly report on Form 10-Q of PECO Energy Company for the quarterly period ended September 30, 2010, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

/s/ Denis P. O’Brien

Denis P. O’Brien

Chief Executive Officer and President

Date: October 22, 2010

184

SECTION 1350 CERT Filed by Phillip S. Barnett for PECO Energy Company

Exhibit 32-8

Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

Date: October 22, 2010

185