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.

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

The number of shares outstanding of each registrant’s common stock as of ~~June~~September 30, 2012 was:


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
BGE		Baltimore Gas and Electric Company
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon’s holding company
CENG		Constellation Energy Nuclear Group, LLC
Constellation		Constellation Energy Group, Inc.
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisitions Company, LLC
Enterprises		Exelon Enterprises Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, LLC
BondCo		RSB BondCo LLC
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
Registrants		Exelon, Generation, ComEd, PECO and BGE, collectively

Other Terms and Abbreviations
Note “ ” of the Exelon 2011 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2011 Annual Report on Form 10-K
Act 11		Pennsylvania Act 11 of 2012
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AEPS		Pennsylvania Alternative Energy Portfolio Standards
AESO		Alberta Electric Systems Operator
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARP		Title IV Acid Rain Program
ARRA of 2009		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
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Air Act		Clean Air Act of 1963, as amended
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
CSAPR		Cross-State Air Pollution Rule
CTC		Competitive Transition Charge
DOE		United States Department of Energy
DOJ		United States Department of Justice
DSP		Default Service Provider
EDF		Electricite de France SA
EE&C		Energy Efficiency and Conservation/Demand Response
EGS		Electric Generation Supplier
EIMA		Illinois Senate Bill 1652 and Illinois House Bill 3036
~~EPA~~		~~United States Environmental Protection Agency~~


GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations
EPA		United States Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GRT		Gross Receipts Tax
GSA		Generation Supply Adjustment
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 EPA		Illinois Environmental Protection Agency
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste
LTIP		Long-Term Incentive Plan
MATS		U.S. EPA Mercury and Air Toxics Rule
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standards
n.m.		not meaningful
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NJDEP		New Jersey Department of Environmental Protection
Non-Regulatory Agreements Units		Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOV		Notice of Violation


GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission


~~GLOSSARY OF TERMS AND ABBREVIATIONS~~

~~Other Terms and Abbreviations~~
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OIESO		Ontario Independent Electricity System Operator
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
POLR		Provider of Last Resort
POR		Purchase of Receivables
PPA		Power Purchase Agreement
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP		Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PV		Photovoltaic
RCRA		Resource Conservation and Recovery Act of 1976, as amended
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units		Nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES		Retail Electric Suppliers
RFP		Request for Proposal
Rider		Reconcilable Surcharge Recovery Mechanism
RMC		Risk Management Committee
RPM		PJM Reliability Pricing Model
RPS		Renewable Energy Portfolio Standards
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SERP		Supplemental Employee Retirement Plan
SFC		Supplier Forward Contract
SGIG		Smart Grid Investment Grant
SILO		Sale-In, Lease-Out
SMP		Smart Meter Program
SNF		Spent Nuclear Fuel
SOS		Standard Offer Service
SPP		Southwest Power Pool
SSCM		Simplified Service Cost Method
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
TEG		Termoelectrica del Golfo
TEP		Termoelectrica Penoles
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity
WECC		Western Electric Coordinating Council

This combined Form 10-Q is being filed separately by the Registrants. Information contained herein relating to any individual ~~registrant~~Registrant is filed by such ~~registrant~~Registrant on its own behalf. No ~~registrant~~Registrant makes any representation as to information relating to any other ~~registrant.~~Registrant.

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 Exelon’s 2011 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 16 of this Report; (b) those factors discussed in the following sections of Constellation’s 2011 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 12, as updated by Part I, ITEM 1. Financial Statements, Note 16 of this Report; and (c) 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.

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 atwww.sec.gov and the Registrants’ websites atwww.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2012			2011			2012			2011			2012			2011			2012			2011
Operating revenues	$	5,954		$	4,496		$	10,640		$	9,451		$	6,565		$	5,254		$	17,205		$	14,705
Operating expenses
Purchased power and fuel		2,606			1,716			4,371			3,716			3,026			2,121			7,398			5,836
Operating and maintenance		1,829			1,226			3,793			2,449			2,156			1,413			5,949			3,863
Depreciation and amortization		494			329			876			656			500			332			1,376			987
Taxes other than income		254			191			448			394			290			207			737			602

Total operating expenses		5,183			3,462			9,488			7,215			5,972			4,073			15,460			11,288

Equity in loss of unconsolidated affiliates		(57	)		—			(79	)		—

Equity in earnings (losses) of unconsolidated affiliates														10			—			(69	)		—
Operating income		714			1,034			1,073			2,236			603			1,181			1,676			3,417

Other income and (deductions)
Interest expense		(250	)		(176	)		(439	)		(350	)		(240	)		(176	)		(678	)		(526	)
Interest expense to affiliates, net		(6	)		(6	)		(12	)		(13	)		(6	)		(6	)		(19	)		(19	)
Other, net		(43	)		101			152			196			101			(142	)		253			54

Total other income and (deductions)		(299	)		(81	)		(299	)		(167	)		(145	)		(324	)		(444	)		(491	)

Income before income taxes		415			953			774			2,069			458			857			1,232			2,926
Income taxes		126			332			284			779			161			255			445			1,034

Net income		289			621			490			1,290			297			602			787			1,892
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		3			1			4			2
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends														1			1			5			3

Net income on common stock		286			620			486			1,288			296			601			782			1,889

Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		1			(1	)		1			(2	)		—			(1	)		1			(3	)
Actuarial loss reclassified to periodic cost		41			34			82			66			44			33			126			100
Transition obligation reclassified to periodic cost		—			1			2			2			—			1			2			2
Pension and non-pension postretirement benefit plans valuation adjustment		(3	)		—			(11	)		39			(67	)		—			(78	)		39
Change in unrealized gain (loss) on cash flow hedges		(156	)		(145	)		59			(191	)
Change in unrealized loss on cash flow hedges														(88	)		(64	)		(29	)		(255	)
Change in unrealized income on equity investments		6			—			6			—			17			—			23			—
Change in unrealized loss on foreign currency translation		(2	)		—			(2	)		—
Change in unrealized loss on marketable securities		(1	)		—			—			—
Change in unrealized gain on foreign currency translation														2			—			—			—

Other comprehensive income (loss)		(114	)		(111	)		137			(86	)		(92	)		(31	)		45			(117	)

Comprehensive income	$	175		$	510		$	627		$	1,204		$	205		$	571		$	832		$	1,775

Average shares of common stock outstanding:
Basic		853			663			779			663			854			663			804			663
Diluted		856			664			781			664			857			665			806			664

Earnings per average common share:
Basic	$	0.34		$	0.93		$	0.62		$	1.94		$	0.35		$	0.91		$	0.97		$	2.85
Diluted	$	0.33		$	0.93		$	0.62		$	1.94		$	0.35		$	0.90		$	0.97		$	2.84

Dividends per common share	$	0.53		$	0.53		$	1.05		$	1.05		$	0.53		$	0.53		$	1.58		$	1.58


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011
Cash flows from operating activities
Net income	$	490		$	1,290		$	787		$	1,892
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, accretion and depletion including nuclear fuel and energy contract amortization		1,895			1,114			2,909			1,702
Impairment of assets held for sale								278			—
Deferred income taxes and amortization of investment tax credits		227			590			263			1,008
Net fair value changes related to derivatives		(323	)		264			(377	)		360
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(70	)		(51	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments								(142	)		90
Other non-cash operating activities		959			378			1,235			703
Changes in assets and liabilities:
Accounts receivable		414			—			240			3
Inventories		45			17			12			(44	)
Accounts payable, accrued expenses and other current liabilities		(1,063	)		(486	)		(837	)		(400	)
Option premiums (paid) received, net		(108	)		38			(122	)		59
Counterparty collateral received (posted), net		451			(494	)		408			(807	)
Income taxes		259			691			465			532
Pension and non-pension postretirement benefit contributions		(90	)		(2,089	)		(131	)		(2,089	)
Other assets and liabilities		(357	)		(249	)		(431	)		(92	)

Net cash flows provided by operating activities		2,729			1,013			4,557			2,917

Cash flows from investing activities
Capital expenditures		(2,816	)		(1,985	)		(4,145	)		(2,972	)
Proceeds from nuclear decommissioning trust fund sales		5,371			1,657			6,262			3,120
Investment in nuclear decommissioning trust funds		(5,483	)		(1,772	)		(6,422	)		(3,293	)
Acquisitions								—			(380	)
Cash acquired from Constellation		964			—			964			—
Proceeds from sales of investments		12			—			26			—
Purchases of investments		(5	)		—			(13	)		—
Change in restricted cash		(15	)		(2	)		(38	)		(532	)
Other investing activities		(12	)		28			41			26

Net cash flows used in investing activities		(1,984	)		(2,074	)		(3,325	)		(4,031	)

Cash flows from financing activities
Changes in short-term debt		179			140			(139	)		462
Issuance of long-term debt		850			599			1,558			1,199
Retirement of long-term debt		(649	)		(2	)		(731	)		(3	)
Dividends paid on common stock		(773	)		(695	)		(1,226	)		(1,044	)
Dividends paid to former Constellation shareholders		(51	)		—			(51	)		—
Proceeds from employee stock plans		42			15			61			26
Other financing activities		(10	)		(46	)		(20	)		(67	)

Net cash flows (used in) provided by financing activities		(412	)		11			(548	)		573

Increase (decrease) in cash and cash equivalents		333			(1,050	)		684			(541	)
Cash and cash equivalents at beginning of period		1,016			1,612			1,016			1,612

Cash and cash equivalents at end of period	$	1,349		$	562		$	1,700		$	1,071


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,349	$	1,016	$	1,602	$	1,016
Cash and cash equivalents of variable interest entities						98		—
Restricted cash and investments		83		40		73		40
Restricted cash and investments of variable interest entities		34		—		67		—
Accounts receivable, net
Customer ($296 and $329 gross accounts receivable pledged as collateral as of June 30, 2012 and December 31, 2011, respectively)		2,886		1,613
Customer ($314 and $329 gross accounts receivable pledged as collateral as of September 30, 2012 and December 31, 2011, respectively)						2,835		1,613
Other		1,252		1,000		1,216		1,000
Accounts receivable, net, variable interest entities		183		—		225		—
Mark-to-market derivative assets		1,170		432		928		432
Unamortized energy contract assets		1,433		13		1,141		13
Inventories, net
Fossil fuel		227		208		264		208
Materials and supplies		772		656		767		656
Deferred income taxes		63		—		254		—
Regulatory assets		867		390		786		390
Other		1,435		345		1,072		345

Total current assets		11,754		5,713		11,328		5,713

Property, plant and equipment, net		42,613		32,570		43,914		32,570
Deferred debits and other assets
Regulatory assets		6,103		4,518		6,192		4,518
Nuclear decommissioning trust funds		6,841		6,507		7,140		6,507
Investments		836		751		838		751
Investments in affiliates		420		15		371		15
Investment in CENG		1,878		—		1,908		—
Goodwill		2,625		2,625		2,625		2,625
Mark-to-market derivative assets		1,241		650		1,039		650
Unamortized energy contracts assets		1,317		388		1,191		388
Pledged assets for Zion Station decommissioning		650		734		631		734
Other		1,156		524		1,176		524

Total deferred debits and other assets		23,067		16,712		23,111		16,712

Total assets	$	77,434	$	54,995	$	78,353	$	54,995


(In millions)	June 30, 2012			December 31, 2011			September 30, 2012			December 31, 2011
	(Unaudited)						(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	376		$	163		$	60		$	163
Short-term notes payable — accounts receivable agreement		225			225			225			225
Long-term debt due within one year		526			828			1,049			828
Long-term debt of variable interest entities due within one year		65			—			70			—
Accounts payable		2,183			1,444			2,359			1,444
Accounts payable of variable interest entities		119			—			132			—
Accrued expenses		1,452			1,255			1,502			1,255
Deferred income taxes		482			1			52			1
Regulatory liabilities		259			197			299			197
Dividends payable		4			349			4			349
Mark-to-market derivative liabilities		829			112			521			112
Unamortized energy contract liabilities		616			—			523			—
Other		947			560			974			560

Total current liabilities		8,083			5,134			7,770			5,134

Long-term debt		17,045			11,799			17,050			11,799
Long-term debt to financing trusts		649			390			649			390
Long-term debt of variable interest entity		479			—			546			—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		10,823			8,253			11,600			8,253
Asset retirement obligations		4,126			3,884			4,866			3,884
Pension obligations		2,610			2,194			2,575			2,194
Non-pension postretirement benefit obligations		2,703			2,263			2,946			2,263
Spent nuclear fuel obligation		1,019			1,019			1,020			1,019
Regulatory liabilities		3,963			3,627			4,000			3,627
Mark-to-market derivative liabilities		578			126			407			126
Unamortized energy contract liabilities		747			—			621			—
Payable for Zion Station decommissioning		464			563			422			563
Other		1,736			1,268			1,691			1,268

Total deferred credits and other liabilities		28,769			23,197			30,148			23,197

Total liabilities		55,025			40,520			56,163			40,520

Commitments and contingencies
Preferred securities of subsidiary		87			87			87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 854 shares and 663 shares outstanding at June 30, 2012 and December 31, 2011, respectively)		16,559			9,107
Treasury stock, at cost (35 shares at June 30, 2012 and December 31, 2011, respectively)		(2,327	)		(2,327	)
Common stock (No par value, 2,000 shares authorized, 854 shares and 663 shares outstanding at September 30, 2012 and December 31, 2011, respectively)								16,594			9,107
Treasury stock, at cost (35 shares at September 30, 2012 and December 31, 2011, respectively)								(2,327	)		(2,327	)
Retained earnings		10,114			10,055			9,959			10,055
Accumulated other comprehensive loss, net		(2,313	)		(2,450	)		(2,405	)		(2,450	)

Total shareholders’ equity		22,033			14,385			21,821			14,385
BGE preference stock not subject to mandatory redemption		193			—			193			—
Noncontrolling interest		96			3			89			3

Total equity		22,322			14,388			22,103			14,388

Total liabilities and shareholders’ equity	$	77,434		$	54,995		$	78,353		$	54,995


(In millions, shares in thousands)	Issued Shares		Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Non-controlling Interest			BGE preference stock not subject to mandatory redemption			Total Equity			Issued Shares		Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Non-controlling Interest			BGE preference stock not subject to mandatory redemption			Total Equity
Balance, December 31, 2011		698,112	$	9,107	$	(2,327	)	$	10,055		$	(2,450	)	$	3		$	—		$	14,388			698,112	$	9,107	$	(2,327	)	$	10,055		$	(2,450	)	$	3		$	—		$	14,388
Net income		—		—		—			486			—			(2	)		6			490			—		—		—			782			—			(6	)		11			787
Long-term incentive plan activity		2,080		87		—			—			—			—			—			87			2,790		122		—			—			—			—			—			122
Common stock dividends		—		—		—			(427	)		—			—			—			(427	)		—		—		—			(878	)		—			—			—			(878	)
Common stock issuance — Constellation merger		188,124		7,365		—			—			—			—			—			7,365
Common stock issuance —Constellation merger																								188,124		7,365		—			—			—			—			—			7,365
Noncontrolling interest acquired		—		—		—			—			—			95			—			95			—		—		—			—			—			92			—			92
BGE preference stock acquired		—		—		—			—			—			—			193			193			—		—		—			—			—			—			193			193
Preferred and preference stock dividends		—		—		—			—			—			—			(6	)		(6	)		—		—		—			—			—			—			(11	)		(11	)
Other comprehensive income net of income taxes of $(146)		—		—		—			—			137			—			—			137
Other comprehensive income net of income taxes of $(87)																								—		—		—			—			45			—			—			45

Balance, June 30, 2012		888,316	$	16,559	$	(2,327	)	$	10,114		$	(2,313	)	$	96		$	193		$	22,322
Balance, September 30, 2012																								889,026	$	16,594	$	(2,327	)	$	9,959		$	(2,405	)	$	89		$	193		$	22,103


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011			2012			2011			2012			2011
Operating revenues
Operating revenues	$	3,345		$	2,209		$	5,718		$	4,546		$	3,558		$	2,517		$	9,276		$	7,063
Operating revenues from affiliates		408			246			774			552			459			304			1,233			856

Total operating revenues		3,753			2,455			6,492			5,098			4,017			2,821			10,509			7,919

Operating expenses
Purchased power and fuel		1,852			841			2,896			1,724			2,122			1,071			5,018			2,795
Operating and maintenance		990			692			2,029			1,372			1,289			713			3,319			2,084
Operating and maintenance from affiliates		176			71			311			145			126			77			437			222
Depreciation and amortization		204			138			357			277			207			139			564			416
Taxes other than income		90			66			164			132			109			67			272			199

Total operating expenses		3,312			1,808			5,757			3,650			3,853			2,067			9,610			5,716

Equity in loss of unconsolidated affiliates		(57	)		—			(79	)		—

Equity in earnings (losses) of unconsolidated affiliates														10			—			(69	)		—
Operating income		384			647			656			1,448			174			754			830			2,203

Other income and (deductions)
Interest expense		(85	)		(45	)		(138	)		(91	)		(85	)		(37	)		(223	)		(128	)
Other, net		(76	)		76			103			152			83			(164	)		185			(12	)

Total other income and (deductions)		(161	)		31			(35	)		61			(2	)		(201	)		(38	)		(140	)

Income before income taxes		223			678			621			1,509			172			553			792			2,063
Income taxes		58			235			289			571			85			167			373			738

Net income		165			443			332			938			87			386			419			1,325
Net loss attributable to noncontrolling interests		(1	)		—			(2	)		—			(4	)		—			(6	)		—

Net income on membership interest		166			443			334			938			91			386			425			1,325

Other comprehensive income (loss), net of income taxes
Change in unrealized loss on cash flow hedges		(266	)		(254	)		(14	)		(323	)		(171	)		(125	)		(185	)		(448	)
Change in unrealized income on equity investments		6			—			6			—			17			—			23			—
Change in unrealized loss on foreign currency translation		(2	)		—			(2	)		—
Change in unrealized income on foreign currency translation														2			—			—			—
Change in unrealized loss on marketable securities		(1	)		—			(1	)		—			—			—			(1	)		—

Other comprehensive loss		(263	)		(254	)		(11	)		(323	)		(152	)		(125	)		(163	)		(448	)

Comprehensive income (loss)	$	(98	)	$	189		$	321		$	615		$	(65	)	$	261		$	256		$	877


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011
Cash flows from operating activities
Net income	$	332		$	938		$	419		$	1,325
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		1,423			735			2,178			1,131
Impairment on assets held for sale								278			—
Deferred income taxes and amortization of investment tax credits		168			298			69			336
Net fair value changes related to derivatives		(307	)		264			(345	)		360
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(70	)		(51	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments								(142	)		90
Other non-cash operating activities		318			168			422			362
Changes in assets and liabilities:
Accounts receivable		306			(139	)		189			(165	)
Receivables from and payables to affiliates, net		(42	)		223			(58	)		210
Inventories		30			(5	)		34			(32	)
Accounts payable, accrued expenses and other current liabilities		(732	)		(78	)		(546	)��		(1	)
Option premiums (paid) received, net		(108	)		38			(122	)		59
Counterparty collateral received (paid), net		443			(525	)		315			(804	)
Income taxes		314			270			565			268
Pension and non-pension postretirement benefit contributions		(35	)		(952	)		(48	)		(952	)
Other assets and liabilities		(174	)		(108	)		(195	)		(65	)

Net cash flows provided by operating activities		1,866			1,076			3,013			2,122

Cash flows from investing activities
Capital expenditures		(1,820	)		(1,270	)		(2,602	)		(1,865	)
Proceeds from nuclear decommissioning trust fund sales		5,371			1,657			6,262			3,120
Investment in nuclear decommissioning trust funds		(5,483	)		(1,772	)		(6,422	)		(3,293	)
Change in restricted cash		6			—
Acquisitions								—			(380	)
Cash acquired from Constellation		708			—			708			—
Other investing activities		(66	)		(3	)		(2	)		(3	)

Net cash flows used in investing activities		(1,284	)		(1,388	)		(2,056	)		(2,421	)

Cash flows from financing activities
Issuance of long-term debt		850			—			957			—
Retirement of long-term debt		(56	)		(1	)		(138	)		(2	)
Change in short-term debt		(42	)		—			(41	)		72
Distribution to member		(891	)		—			(1,384	)		(61	)
Contribution from member								—			30
Other financing activities		(9	)		(34	)		(17	)		(53	)

Net cash flows used in financing activities		(148	)		(35	)		(623	)		(14	)

Increase (decrease) in cash and cash equivalents		434			(347	)		334			(313	)
Cash and cash equivalents at beginning of period		496			456			496			456

Cash and cash equivalents at end of period	$	930		$	109		$	830		$	143


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	930	$	496	$	732	$	496
Cash and cash equivalents of variable interest entities						98		—
Restricted cash and cash equivalents		2		5		1		5
Restricted cash and cash equivalents, variable interest entities		12		—
Restricted cash and cash equivalents of variable interest entities						19		—
Accounts receivable, net
Customer		1,579		578		1,580		578
Other		254		257		291		257
Accounts receivable, net, variable interest entities		183		—		225		—
Mark-to-market derivative assets		1,170		432		928		432
Mark-to-market derivative assets with affiliates		506		503		352		503
Receivables from affiliates		144		109		130		109
Unamortized energy contract assets		1,433		13		1,141		13
Inventories, net
Fossil fuel		134		120		136		120
Materials and supplies		628		556		620		556
Other		1,110		148		905		148

Total current assets		8,085		3,217		7,158		3,217

Property, plant and equipment, net		17,702		13,475		18,708		13,475
Deferred debits and other assets
Nuclear decommissioning trust funds		6,841		6,507		7,140		6,507
Investments		82		41		82		41
Investments in affiliates		397		1		348		1
Investment in CENG		1,878		—		1,908		—
Mark-to-market derivative assets		1,227		635		1,026		635
Mark-to-market derivative assets with affiliates		—		191		—		191
Prepaid pension asset		2,057		2,068		2,021		2,068
Pledged assets for Zion Station decommissioning		650		734		631		734
Unamortized energy contract assets		1,317		388		1,191		388
Other		851		176		877		176

Total deferred debits and other assets		15,300		10,741		15,224		10,741

Total assets	$	41,087	$	27,433	$	41,090	$	27,433


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	10	$	2	$	11	$	2
Long-term debt due within one year		23		3		23		3
Long-term debt due within one year of variable interest entities		3		—		4		—
Accounts payable		1,310		753		1,501		753
Accounts payable of variable interest entities		119		—		132		—
Accrued expenses		885		779		1,106		779
Payables to affiliates		115		58		99		58
Deferred income taxes		567		244		69		244
Mark-to-market derivative liabilities		810		103		504		103
Unamortized energy contract liabilities		506		—		429		—
Other		378		202		377		202

Total current liabilities		4,726		2,144		4,255		2,144

Long-term debt		7,163		3,674		7,148		3,674
Long-term debt of variable interest entities		180		—		208		—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,892		3,966		5,410		3,966
Asset retirement obligations		3,997		3,767		4,730		3,767
Non-pension postretirement benefit obligations		815		703		849		703
Spent nuclear fuel obligation		1,019		1,019		1,020		1,019
Payables to affiliates		2,352		2,222		2,383		2,222
Mark-to-market derivative liabilities		485		29		355		29
Unamortized energy contract liabilities		696		—		589		—
Payable for Zion Station decommissioning		464		563		422		563
Other		793		638		791		638

Total deferred credits and other liabilities		15,513		12,907		16,549		12,907

Total liabilities		27,582		18,725		28,160		18,725

Commitments and contingencies
Equity
Member’s equity
Membership interest		8,828		3,556		8,814		3,556
Undistributed earnings		3,675		4,232		3,273		4,232
Accumulated other comprehensive income, net		904		915		752		915

Total member’s equity		13,407		8,703		12,839		8,703
Noncontrolling interest		98		5		91		5

Total equity		13,505		8,708		12,930		8,708

Total liabilities and equity	$	41,087	$	27,433	$	41,090	$	27,433


	Three Months Ended June 30,							Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2012				2011			2012			2011			2012			2011			2012			2011
Operating revenues
Operating revenues	$	1,280			$	1,444		$	2,669		$	2,909		$	1,484		$	1,783		$	4,152		$	4,692
Operating revenues from affiliates		1				—			1			1			—			1			2			2

Total operating revenues		1,281				1,444			2,670			2,910			1,484			1,784			4,154			4,694

Operating expenses
Purchased power		384				588			757			1,214			498			773			1,255			1,986
Purchased power from affiliate		203				128			451			291			180			159			631			450
Operating and maintenance		293				232			569			461			313			356			882			817
Operating and maintenance from affiliate		38				36			81			73			37			40			118			113
Depreciation and amortization		152				136			300			270			157			135			458			405
Taxes other than income		69				70			144			147			81			78			224			226

Total operating expenses		1,139		��		1,190			2,302			2,456			1,266			1,541			3,568			3,997

Operating income		142				254			368			454			218			243			586			697

Other income and (deductions)
Interest expense		(71	)			(82	)		(150	)		(164	)		(71	)		(82	)		(221	)		(246	)
Interest expense to affiliates, net		(3	)			(4	)		(6	)		(8	)		(3	)		(4	)		(9	)		(11	)
Other, net		3				4			7			8			5			16			12			24

Total other income and (deductions)		(71	)			(82	)		(149	)		(164	)		(69	)		(70	)		(218	)		(233	)

Income before income taxes		71				172			219			290			149			173			368			464
Income taxes		29				58			90			107			59			61			149			169

Net income		42				114			129			183			90			112			219			295

Other comprehensive income, net of income taxes
Change in unrealized gain on marketable securities		—				—			1			—			—			—			1			—

Other comprehensive income		—				—			1			—			—			—			1			—

Comprehensive income	$	42			$	114		$	130		$	183		$	90		$	112		$	220		$	295


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011
Cash flows from operating activities
Net income	$	129		$	183		$	219		$	295
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		300			270			458			405
Deferred income taxes and amortization of investment tax credits		116			184			198			527
Other non-cash operating activities		241			115			310			210
Changes in assets and liabilities:
Accounts receivable		(26	)		(62	)		22			(4	)
Receivables from and payables to affiliates, net		(18	)		(23	)		(32	)		(13	)
Inventories		(7	)		(7	)		(11	)		(11	)
Accounts payable, accrued expenses and other current liabilities		(54	)		(108	)		(49	)		(160	)
Counterparty collateral received, net		8			31
Counterparty collateral received (paid), net								93			(3	)
Income taxes		149			321			116			211
Pension and non-pension postretirement benefit contributions		(12	)		(871	)		(19	)		(871	)
Other assets and liabilities		(104	)		38			(124	)		29

Net cash flows provided by operating activities		722			71			1,181			615

Cash flows from investing activities
Capital expenditures		(585	)		(495	)		(896	)		(758	)
Proceeds from sales of investments		12			4			26			4
Purchases of investments		(5	)		(2	)		(13	)		(2	)
Change in restricted cash								—			(536	)
Other investing activities		11			20			12			16

Net cash flows used in investing activities		(567	)		(473	)		(871	)		(1,276	)

Cash flows from financing activities
Changes in short-term debt		178			—			35			—
Issuance of long-term debt		—			599			—			1,199
Retirement of long-term debt		(450	)		(1	)		(450	)		(1	)
Dividends paid on common stock		(85	)		(150	)		(95	)		(225	)
Other financing activities		(3	)		(2	)		(3	)		(6	)

Net cash flows (used in) provided by financing activities		(360	)		446			(513	)		967

(Decrease) Increase in cash and cash equivalents		(205	)		44			(203	)		306
Cash and cash equivalents at beginning of period		234			50			234			50

Cash and cash equivalents at end of period	$	29		$	94		$	31		$	356


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	29	$	234	$	31	$	234
Restricted cash		3		3		—		3
Accounts receivable, net
Customer		675		655		602		655
Other		245		385		274		385
Inventories, net		88		81		92		81
Deferred income taxes		74		61		87		61
Counterparty collateral deposited		84		90		—		90
Regulatory assets		726		657		511		657
Other		23		22		27		22

Total current assets		1,947		2,188		1,624		2,188

Property, plant and equipment, net		13,428		13,121		13,611		13,121
Deferred debits and other assets
Regulatory assets		583		699		589		699
Investments		15		21		9		21
Investments in affiliates		6		6		6		6
Goodwill		2,625		2,625		2,625		2,625
Receivables from affiliates		1,963		1,860		2,024		1,860
Prepaid pension asset		1,736		1,803		1,698		1,803
Other		282		315		285		315

Total deferred debits and other assets		7,210		7,329		7,236		7,329

Total assets	$	22,585	$	22,638	$	22,471	$	22,638


(In millions)	June 30, 2012		December 31, 2011			September 30, 2012		December 31, 2011
	(Unaudited)					(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	178	$	—		$	35	$	—
Long-term debt due within one year		125		450			252		450
Accounts payable		349		325			326		325
Accrued expenses		244		318			220		318
Payables to affiliates		96		111			84		111
Customer deposits		138		136			137		136
Regulatory liabilities		146		137			172		137
Mark-to-market derivative liability		19		9			17		9
Mark-to-market derivative liability with affiliate		506		503			352		503
Other		117		82			128		82

Total current liabilities		1,918		2,071			1,723		2,071

Long-term debt		5,091		5,215			4,965		5,215
Long-term debt to financing trust		206		206			206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,106		3,993			4,201		3,993
Asset retirement obligations		92		89			99		89
Non-pension postretirement benefits obligations		330		271			359		271
Regulatory liabilities		3,149		3,042			3,206		3,042
Mark-to-market derivative liability		92		97			53		97
Mark-to-market derivative liability with affiliate		—		191			—		191
Other		506		426			484		426

Total deferred credits and other liabilities		8,275		8,109			8,402		8,109

Total liabilities		15,490		15,601			15,296		15,601

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588			1,588		1,588
Other paid-in capital		5,016		5,003			5,016		5,003
Retained earnings		491		447			571		447
Accumulated other comprehensive loss, net		—		(1	)		—		(1	)

Total shareholders’ equity		7,095		7,037			7,175		7,037

Total liabilities and shareholders’ equity	$	22,585	$	22,638		$	22,471	$	22,638


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011			2012			2011			2012			2011
Operating revenues
Operating revenues	$	714		$	842		$	1,588		$	1,994		$	805		$	944		$	2,393		$	2,938
Operating revenues from affiliates		1			—			2			2			1			2			3			4

Total operating revenues		715			842			1,590			1,996			806			946			2,396			2,942

Operating expenses
Purchased power and fuel		171			293			472			785			155			327			626			1,112
Purchased power from affiliate		125			115			235			257			171			137			407			394
Operating and maintenance		146			150			318			334			172			195			491			529
Operating and maintenance from affiliates		26			22			57			44			27			24			83			68
Depreciation and amortization		54			50			107			98			55			51			161			150
Taxes other than income		42			51			74			106			48			59			122			165

Total operating expenses		564			681			1,263			1,624			628			793			1,890			2,418

Operating income		151			161			327			372			178			153			506			524

Other income and (deductions)
Interest expense		(28	)		(31	)		(56	)		(62	)		(29	)		(31	)		(85	)		(93	)
Interest expense to affiliates, net		(3	)		(3	)		(6	)		(6	)		(3	)		(3	)		(9	)		(9	)
Other, net		2			3			5			8			2			3			6			11

Total other income and (deductions)		(29	)		(31	)		(57	)		(60	)		(30	)		(31	)		(88	)		(91	)

Income before income taxes		122			130			270			312			148			122			418			433
Income taxes		42			47			93			102			25			17			118			119

Net income		80			83			177			210			123			105			300			314
Preferred security dividends		1			1			2			2			1			1			3			3

Net income on common stock		79			82			175			208			122			104			297			311

Comprehensive income, net of income taxes
Net income		80			83			177			210			123			105			300			314
Other comprehensive income, net of income taxes
Change in unrealized gains on marketable securities		—			—			1			—			—			—			1			—

Other comprehensive income		—			—			1			—			—			—			1			—

Comprehensive income	$	80		$	83		$	178		$	210		$	123		$	105		$	301		$	314


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011
Cash flows from operating activities
Net income	$	177		$	210		$	300		$	314
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		107			98			161			150
Deferred income taxes and amortization of investment tax credits		19			91			27			181
Other non-cash operating activities		66			44			96			74
Changes in assets and liabilities:
Accounts receivable		62			221			36			241
Receivables from and payables to affiliates, net		9			(218	)		15			(217	)
Inventories		26			29			10			—
Accounts payable, accrued expenses and other current liabilities		(83	)		(11	)		(75	)		24
Income taxes		121			113			127			27
Pension and non-pension postretirement benefit contributions		(8	)		(110	)		(12	)		(110	)
Other assets and liabilities		(87	)		(108	)		(57	)		(28	)

Net cash flows provided by operating activities		409			359			628			656

Cash flows from investing activities
Capital expenditures		(179	)		(209	)		(274	)		(321	)
Changes in Exelon intercompany money pool		18			(171	)		5			(91	)
Change in restricted cash		(3	)		(2	)		2			(2	)
Other investing activities		7			11			8			12

Net cash flows used in investing activities		(157	)		(371	)		(259	)		(402	)

Cash flows from financing activities
Issuance of long-term debt								350			—
Dividends paid on common stock		(172	)		(184	)		(258	)		(268	)
Dividends paid on preferred securities		(2	)		(2	)		(3	)		(3	)
Contributions from parent								—			18
Other financing activities		—			(5	)		(4	)		(5	)

Net cash flows used in financing activities		(174	)		(191	)
Net cash flows provided by (used in) financing activities								85			(258	)

Increase (decrease) in cash and cash equivalents		78			(203	)		454			(4	)
Cash and cash equivalents at beginning of period		194			522			194			522

Cash and cash equivalents at end of period	$	272		$	319		$	648		$	518


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	272	$	194	$	648	$	194
Restricted cash and cash equivalents		5		2		—		2
Accounts receivable, net
Customer ($296 and $329 gross accounts receivable pledged as collateral as of June 30, 2012 and December 31, 2011, respectively)		307		380
Accounts receivable, net ($314 and $329 gross accounts receivable pledged as collateral as of September 30, 2012 and December 31, 2011, respectively)
Customer						294		380
Other		230		376		240		376
Inventories, net
Fossil fuel		58		87		75		87
Materials and supplies		21		18		20		18
Deferred income taxes		31		25		39		25
Receivable from Exelon intercompany money pool		64		82		77		82
Prepaid utility taxes		99		1		57		1
Regulatory assets		54		39		42		39
Other		50		39		38		39

Total current assets		1,191		1,243		1,530		1,243

Property, plant and equipment, net		5,960		5,874		5,996		5,874
Deferred debits and other assets
Regulatory assets		1,216		1,216		1,323		1,216
Investments		21		22		23		22
Investments in affiliates		8		8		8		8
Receivable from affiliates		392		365		362		365
Prepaid pension asset		379		382		378		382
Other		37		46		41		46

Total deferred debits and other assets		2,053		2,039		2,135		2,039

Total assets	$	9,204	$	9,156	$	9,661	$	9,156


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term notes payable — accounts receivable agreement	$	225	$	225	$	225	$	225
Long-term debt due within one year		375		375		375		375
Accounts payable		198		262		200		262
Accrued expenses		71		83		87		83
Payables to affiliates		77		62		76		62
Customer deposits		52		53		51		53
Regulatory liabilities		91		60		105		60
Other		34		25		26		25

Total current liabilities		1,123		1,145		1,145		1,145

Long-term debt		1,598		1,597		1,947		1,597
Long-term debt to financing trusts		184		184		184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,214		2,170		2,281		2,170
Asset retirement obligations		28		28		29		28
Non-pension postretirement benefits obligations		303		288		310		288
Regulatory liabilities		606		585		582		585
Other		119		134		118		134

Total deferred credits and other liabilities		3,270		3,205		3,320		3,205

Total liabilities		6,175		6,131		6,596		6,131

Commitments and contingencies
Preferred securities		87		87		87		87
Shareholders’ equity
Common stock		2,379		2,379		2,379		2,379
Retained earnings		562		559		598		559
Accumulated other comprehensive income, net		1		—		1		—

Total shareholders’ equity		2,942		2,938		2,978		2,938

Total liabilities and shareholders’ equity	$	9,204	$	9,156	$	9,661	$	9,156


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011			2012			2011			2012			2011
Operating revenues
Operating revenues	$	614		$	672		$	1,307		$	1,647		$	716		$	742		$	2,023		$	2,388
Operating revenues from affiliates		2			2			5			3			4			3			9			6

Total operating revenues		616			674			1,312			1,650			720			745			2,032			2,394

Operating expenses
Purchased power and fuel		201			267			494			753			253			268			747			1,021
Purchased power from affiliate		84			73			176			130			120			137			296			267
Operating and maintenance		135			129			288			249			172			184			460			433
Operating and maintenance from affiliates		26			38			68			70			29			26			97			96
Depreciation and amortization		71			67			150			144			68			60			218			205
Taxes other than income		47			46			95			96			48			47			143			143

Total operating expenses		564			620			1,271			1,442			690			722			1,961			2,165

Operating income		52			54			41			208			30			23			71			229

Other income and (deductions)
Interest expense		(34	)		(32	)		(75	)		(66	)		(35	)		(32	)		(110	)		(97	)
Other, net		7			6			13			13			5			8			18			22

Total other income and (deductions)		(27	)		(26	)		(62	)		(53	)		(30	)		(24	)		(92	)		(75	)

Income (loss) before income taxes		25			28			(21	)		155			—			(1	)		(21	)		154
Income taxes		9			12			(7	)		58			—			(3	)		(7	)		55

Net income (loss)		16			16			(14	)		97			—			2			(14	)		99
Preference stock dividends		3			3			6			6			4			4			10			10

Net income (loss) on common stock	$	13		$	13		$	(20	)	$	91		$	(4	)	$	(2	)	$	(24	)	$	89

Comprehensive income (loss)	$	16		$	16		$	(14	)	$	97		$	—		$	2		$	(14	)	$	99


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2012			2011			2012			2011
Cash flows from operating activities
Net (loss) income	$	(14	)	$	97		$	(14	)	$	99
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		150			144			218			205
Deferred income taxes and amortization of investment tax credits		91			59			101			93
Other non-cash operating activities		100			54			147			98
Changes in assets and liabilities:
Accounts receivable		92			94			11			90
Receivables from and payables to affiliates, net		(3	)		(10	)		4			(5	)
Inventories		37			7			21			(20	)
Accounts payable, accrued expenses and other current liabilities		(71	)		(24	)		(16	)		(18	)
Income taxes		(48	)		56			(50	)		56
Pension and non-pension postretirement benefit contributions		(8	)		(7	)		(13	)		(17	)
Other assets and liabilities		43			3			(86	)		(154	)

Net cash flows provided by operating activities		369			473			323			427

Cash flows from investing activities
Capital expenditures		(282	)		(283	)		(402	)		(416	)
Change in restricted cash		8			4			(19	)		(22	)
Other investing activities		(10	)		—			8			—

Net cash flows used in investing activities		(284	)		(279	)		(413	)		(438	)

Cash flows from financing activities
Changes in short-term debt								—			140
Issuance of long-term debt								250			—
Repayment of long-term debt		(141	)		(30	)		(141	)		(30	)
Dividends paid on common stock		—			(85	)		—			(85	)
Dividends paid on preference stock		(6	)		(6	)		(10	)		(10	)
Contributions from parent		66			—			66			—
Other financing activities		—			(2	)		(3	)		(3	)

Net cash flows used in financing activities		(81	)		(123	)
Net cash flows provided by financing activities								162			12

Increase in cash and cash equivalents		4			71			72			1
Cash and cash equivalents at beginning of period		49			50			49			50

Cash and cash equivalents at end of period	$	53		$	121		$	121		$	51


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	53	$	49	$	121	$	49
Restricted cash and cash equivalents of variable interest entity		22		30		49		30
Accounts receivable, net
Customer		324		428		358		428
Other		99		90		120		90
Income taxes receivable		67		21		61		21
Inventories, net
Gas held in storage		35		74		53		74
Materials and supplies		36		34		34		34
Prepaid utility taxes		5		56		85		56
Regulatory assets		179		174		189		174
Other		8		12		8		12

Total current assets		828		968		1,078		968

Property, plant and equipment, net		5,294		5,132		5,378		5,132
Deferred debits and other assets
Regulatory assets		550		550		534		550
Investments		5		—		5		—
Investments in affiliates		8		8		8		8
Prepaid pension asset		490		514		477		514
Other		25		33		24		29

Total deferred debits and other assets		1,078		1,105		1,048		1,101

Total assets	$	7,200	$	7,205	$	7,504	$	7,201


(In millions)	June 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	—	$	110	$	400	$	110
Long-term debt of variable interest entity due within one year		65		63		65		63
Accounts payable		161		210		190		210
Accrued expenses		110		148		125		148
Deferred income taxes		66		59		56		59
Payables to affiliates		44		41		44		41
Customer deposits		80		84		75		84
Regulatory liabilities		22		18		22		18
Other		59		25		71		25

Total current liabilities		607		758		1,048		758

Long-term debt		1,597		1,596		1,446		1,596
Long-term debt to financing trust		258		258		258		258
Long-term debt of variable interest entity		299		332		299		332
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,577		1,491		1,598		1,491
Asset retirement obligations		8		1		8		1
Non-pension postretirement benefits obligations		211		212		208		212
Regulatory liabilities		208		200		212		200
Other		88		56		84		52

Total deferred credits and other liabilities		2,092		1,960		2,110		1,956

Total liabilities		4,853		4,904		5,161		4,900

Commitments and contingencies
Shareholders’ equity
Common stock		1,360		1,294		1,360		1,294
Retained earnings		797		817		793		817

Total shareholders’ equity		2,157		2,111		2,153		2,111

Preference stock not subject to mandatory redemption		190		190		190		190

Total equity		2,347		2,301		2,343		2,301

Total liabilities and shareholders’ equity	$	7,200	$	7,205	$	7,504	$	7,201


(In millions)	Common Stock		Retained Earnings			Total Shareholders’ Equity			Preference stock not subject to mandatory redemption		Total Equity			Common Stock		Retained Earnings			Total Shareholders’ Equity			Preference stock not subject to mandatory redemption		Total Equity
Balance, December 31, 2011	$	1,294	$	817		$	2,111		$	190	$	2,301		$	1,294	$	817		$	2,111		$	190	$	2,301
Net loss		—		(14	)		(14	)		—		(14	)		—		(14	)		(14	)		—		(14	)
Preference stock dividends		—		(6	)		(6	)		—		(6	)		—		(10	)		(10	)		—		(10	)
Contribution from parent		66		—			66			—		66			66		—			66			—		66

Balance, June 30, 2012	$	1,360	$	797		$	2,157		$	190	$	2,347
Balance, September 30, 2012														$	1,360	$	793		$	2,153		$	190	$	2,343

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon’s principal, wholly owned subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (the “Merger Agreement”). As a result of the merger transaction, Generation includes the former Constellation customer supply and generation businesses. BGE, formerly Constellation’s regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 3 — Merger and Acquisitions for further information regarding the merger transaction.

For financial statement purposes, beginning on March 12, 2012, disclosures that solely relate to Constellation or BGE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.

BGE was acquired through a transaction under common control (RF HoldCo LLC) and Exelon did not apply push-down accounting to BGE. As a result, BGE continues to maintain its ~~current~~ reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 and the financial position as of ~~June~~September 30, 2012 and December 31, 2011. However, for Exelon’s financial reporting, Exelon is reporting BGE activity from March 12, 2012 through ~~June~~September 30, 2012.

Each of Generation’s, ComEd’s, PECO’s and BGE’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of ~~June~~September 30, 2012 and 2011 and for the three and ~~six~~nine months then ended are unaudited but, in the opinion of the management of each Registrant ~~includes~~include all adjustments that are considered necessary for a fair statement of ~~its~~the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The ~~December 31,~~

December 31, 2011 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in BGE’s Consolidated Statements of Cash Flows, Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income and in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income or cash flows from operating activities. 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 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 Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2011 Form 10-K.

See Note 1 and Note 4 of the 2011 Form 10-K for Constellation and BGE for further information regarding investments in VIEs.

At ~~June~~September 30, 2012, Exelon’s, Generation’s and BGE’s consolidated financial statements include the following balances for the consolidated VIEs ~~which~~that were acquired as part of the merger:


	June 30, 2012						September 30, 2012
	Exelon		Generation		BGE		Exelon		Generation		BGE
Current assets	$	355	$	333	$	22	$	398	$	348	$	49
Noncurrent assets		446		403		—		471		432		—

Total assets	$	801	$	736	$	22	$	869	$	780	$	49

Current liabilities	$	280	$	210	$	70	$	269	$	193	$	75
Noncurrent liabilities		553		212		299		573		235		299

Total liabilities	$	833	$	422	$	369	$	842	$	428	$	374

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include three categories: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. As of the balance sheet date, the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the majority of the energy contracts and fuel purchase contracts with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Exelon and Generation for the deliveries associated with the current billing cycles under the contracts. Further, Exelon and Generation have not provided or guaranteed the debt or equity support, or liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of the involvement with these VIEs.

As of ~~June~~September 30, 2012, Exelon and Generation did have exposure to loss associated with six VIEs for which they were not the primary beneficiary; including certain equity method investments and certain energy contracts. The following table presents summary information about the unconsolidated VIE entities for which Exelon and Generation have exposure to loss, which were added as a result of the merger:


June 30, 2012	Energy Contract VIEs		Equity Method Investment VIEs		Total
September 30, 2012							Energy Contract VIEs		Equity Method Investment VIEs		Total
Total assets(a)	$	283	$	363	$	646	$	280	$	342	$	622
Total liabilities(a)		220		116		336		217		95		312
Registrants’ ownership interest(a)		—		98		98		—		98		98
Other ownership interests(a)		63		149		212		63		149		212
Registrants’ maximum exposure to loss:
Letters of credit		11		—		11		8		—		8
Carrying amount of equity method investments		—		77		77		—		78		78
Debt and payment guarantees		—		5		5		—		5		5

During the ~~six~~nine months ended ~~June~~September 30, 2012, ComEd, PECO, BGE and Generation assessed their contracts and determined that, other than the items discussed in this note there were no changes in their variable interests, primary beneficiary determinations or conclusions regarding consolidation of VIEs from December 31, 2011. See Note 1 of the Exelon 2011 Form 10-K and Note 1 and Note 4 of the 2011 10-K for BGE for further information regarding the Registrants’ VIEs.

RF HoldCo LLC, a bankruptcy-remote special purpose subsidiary, holds all of Exelon’s common equity interests in BGE. This subsidiary is not a VIE. However, due to Exelon’s ownership of 100% of the voting interests of RF HoldCo LLC, Exelon consolidates this subsidiary as a voting interest entity.

BGE and RF HoldCo are separate legal entities and are not liable for the debts of Exelon. Accordingly, creditors of Exelon may not satisfy their debts from the assets of BGE and RF HoldCo LLC except as required by applicable law or regulation. Similarly, Exelon is not liable for the debts of BGE or RF HoldCo LLC. Accordingly, creditors of BGE and RF HoldCo LLC may not satisfy their debts from the assets of Exelon except as required by applicable law or regulation.

The following recently issued accounting standard was adopted by the Registrants during the period.

In May 2011, the FASB issued authoritative guidance amending existing guidance for measuring and disclosing fair value. The new guidance does not impact the fair value measurements included in the Registrants’ Consolidated Financial Statements as of ~~June~~September 30, 2012. The guidance is effective for the Registrants beginning with the period ended March 31, 2012 and is required to be applied prospectively. However, the Company updated the existing fair value disclosures during the first quarter of 2012 to comply with the requirements for this standard. See Note 7 — Fair Value of Financial Assets and Liabilities for the new disclosures.

On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including the customer supply and generation businesses that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.

Constellation’s shareholders received 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock outstanding as of March 12, 2012. Generally, all outstanding Constellation equity-based compensation awards were converted into Exelon equity-based compensation awards using the same ratio. See Note 14 — Stock-Based Compensation Plans for further information.

In December 2011, Exelon and Constellation reached a settlement with the State of Maryland and the City of Baltimore and other interested parties in connection with the regulatory proceedings related to the merger that

were pending before the MDPSC. As part of this settlement and the application for approval of the merger by MDPSC, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of more than $1 billion.

On February 17, 2012, the MDPSC approved the merger with conditions. Many of the conditions were reflective of the settlement agreements described above. The following costs were recognized after the closing of the merger and are included in Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income for the ~~six~~nine months ended ~~June~~September 30, 2012:


Description	Payment Period	BGE			Generation		Exelon			Statement of Operations Location	Payment Period	BGE			Generation		Exelon			Statement of Operations Location
BGE rate credit of $100 per residential customer(a)	Q2 2012	$	113		$	—	$	113		Revenues	Q2 2012	$	113		$	—	$	113		Revenues
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers	2012 to 2014		—			—		113.5		O&M Expense	2012 to 2014		—			—		113.5		O&M Expense
Contribution for renewable energy, energy efficiency or related projects in Baltimore	2012 to 2014		—			—		2		O&M Expense	2012 to 2014		—			—		2		O&M Expense
Charitable contributions at $7 million per year for 10 years	2012 to 2021		28			35		70		O&M Expense	2012 to 2021		28			35		70		O&M Expense
State funding for offshore wind development projects	Q2 2012		—			—		32		O&M Expense	Q2 2012		—			—		32		O&M Expense
Miscellaneous tax benefits	Q2 2012		(2	)		—		(2	)	Taxes Other Than Income	Q2 2012		(2	)		—		(2	)	Taxes Other Than Income

Total		$	139		$	35	$	328.5				$	139		$	35	$	328.5

In addition to these costs, the estimate of $1 billion of direct investment includes $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. The construction is expected to be completed in 2 to 3 years. The $1 billion estimate also includes $625 million for Exelon and Generation’s commitment to develop 285 – 300 MW of new generation in Maryland, expected to be completed over a period of 10 years. Such costs, which are expected to be primarily capital in nature, will be recognized as incurred. As of ~~June~~September 30, 2012, amounts reflected in the Exelon and Generation consolidated financial statements for these expenditure commitments were immaterial. ~~Such costs, which are expected to be primarily capital in nature, will be recognized as incurred.~~

Pursuant to the MDPSC merger approval conditions, BGE is restricted from paying any dividend on its common shares through the end of 2014, is required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and is not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process.

Associated with certain of the regulatory approvals required for the merger, Exelon and Constellation agreed to enter into contracts to sell three Constellation generating stations located in PJM within 150 days (subsequently extended 30 days by the DOJ) following the merger completion and will be required to complete the divestitures within 30 days after receipt of regulatory approvals. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, include base-load, coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity. In October 2011, Exelon and Constellation reached a settlement with the PJM Independent Market Monitor, who had previously raised market power concerns regarding the merger. The settlement

contains a number of commitments by Exelon, including limiting the universe of potential buyers of the divested assets to entities without significant market shares in the relevant PJM markets. The settlement also includes assurances about how Generation will bid its units into the PJM markets. The proposed divestiture and the settlement with the PJM Market Monitor were filed with FERC and the MDPSC and were included in their final orders approving the merger.

As of June 30, 2012, these assets are classified as held for sale assets and included in the other current assets balance on Exelon’s and Generation’s Consolidated Balance Sheets. In accordance with ASC 820, these assets are valued at estimated fair value less costs to sell, whereby fair value is defined as the price that would be received to sell the assets in an orderly transaction between market participants.

On August 8, 2012, a subsidiary of Generation reached an agreement to sell these three Maryland generating stations and associated assets to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC. The ~~transaction, which is subject to~~DOJ approved the buyer on October 18, 2012 and the final FERC approval ~~by FERC and DOJ,~~was obtained on October 19, 2012; the transaction is expected to close in the fourth quarter 2012. The agreement includes a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in an estimated ~~sales price~~net proceeds from the sale of approximately ~~$400~~$356 million. Decisions by certain market participants to remove themselves from the bidding process, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realized sales proceeds below ~~the~~Generation’s estimated fair value of the Maryland generating ~~stations than would have been achieved in an orderly transaction. Therefore,~~stations. Consequently, Exelon and Generation ~~will record~~recorded a pre-tax loss ~~estimated to be approximately $275~~of $278 million in operating and maintenance expense in the third quarter of 2012 to reflect the difference between the estimated sales price and carrying value. The final loss amount will be updated for adjustments related to fuel inventory, capital expenditures, and timing of the closing.

As of September 30, 2012, these assets, classified as held for sale, are valued at estimated fair value less costs to sell of $339 million, after reflecting the $278 million impairment, and are included in the other current assets balance on Exelon’s and Generation’s Consolidated Balance Sheets.

Subsequent to the merger, Generation discovered that, for the first two weeks following merger close, due to a software ~~error~~error. Generation inadvertently bid certain generating units into the PJM energy market at prices that slightly exceeded the cost-based caps to which it had agreed. This error was a violation of the commitments made in connection with merger approvals by DOJ, FERC and the MDPSC. Generation reported the error to the DOJ, FERC and the MDPSC and committed to remedy the impacts of its error. The MDPSC held a hearing to review the error, and accepted Generation’s proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for some minor adjustments to the cost build up for certain of its PJM units. Generation ~~is coordinating~~has coordinated with PJM to determine the impact on Generation’s revenues and the market from this error and these adjustments, and Generation ~~will work~~has worked with PJM to reverse the financial impacts. Generation ~~cannot predict what~~is in discussions with the DOJ regarding resolution of this matter. The final ~~action DOJ, FERC~~resolution is not expected to have a material impact on Exelon’s or ~~the MDPSC might take in connection with this error and these adjustments.~~Generation’s results of operations, cash flows or financial position.

In addition, in January 2012, Exelon and Constellation reached an agreement with EDF under which EDF withdrew its opposition to the Exelon-Constellation merger. The terms of the agreement address CENG, a joint venture between Constellation and EDF that owns and operates a total of three nuclear facilities with a total of five generating units in Maryland and New York. The agreement reaffirms the terms of the joint venture. The agreement did not include any exchange of monetary consideration, and Exelon does not expect the agreement will have a material effect on Exelon’s and Generation’s future results of operations, financial position and cash flows.

Exelon was named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. On June 26, 2012, the court approved the settlement and entered final judgment.

The total consideration in the merger was based on the opening price of a share of Exelon common stock on March 12, 2012 (in millions):

All options to purchase Constellation common stock under various equity agreements were converted into options to acquire a number of shares of Exelon common stock (as adjusted for the exchange ratio) at an option price. All Constellation unvested restricted stock awards granted prior to April 28, 2011, that were outstanding immediately prior to the consummation of the Merger, became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and converted into Exelon common stock at the exchange ratio in accordance with the applicable stock plan and award agreement terms. All Constellation restricted stock awards that remained unvested on a pro rata basis pursuant to the foregoing formula, and any Constellation unvested restricted stock awards granted after April 28, 2011, have been assumed by Exelon and automatically converted into shares of unvested restricted stock of Exelon at the exchange ratio. Likewise, all restricted stock units granted prior to April 28, 2011 under the Constellation Plans and outstanding immediately prior to the completion of the Initial Merger became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and have been assumed by Exelon and automatically converted into a number of shares of Exelon common stock at the exchange ratio.

The fair value of Constellation’s non-regulated business assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.

The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to rate-setting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE’s tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE’s debt, fuel supply contracts and regulatory assets not earning a return, the ~~difference between fair value and~~

difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1 — Basis of Presentation for additional information on BGE’s push-down accounting treatment. Also see Note 4 ~~— Regulatory~~—Regulatory Matters for additional information on BGE’s regulatory assets.

The preliminary valuations performed in the first quarter of 2012 to assess the fair values of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2012. The allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities ~~assumed; however, Exelon expects to finalize these amounts by the end of 2012, if not sooner.~~assumed. The preliminary valuations performed in the first quarter of 2012 were updated in the second ~~quarter~~and third quarters of 2012, with the most significant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply contracts and fuel contracts, unregulated property, plant and equipment and investments in affiliates. The preliminary amounts recognized are subject to further revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and material changes could require the financial statements to be retroactively amended.

The updated preliminary purchase price allocation of the Initial Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation at ~~June~~September 30, 2012 was as follows:


Preliminary Purchase Price Allocation	Exelon		Generation
Preliminary Purchase Price Allocation, excluding amortization					Exelon		Generation
Current assets	$	4,944	$	3,649	$	4,936	$	3,638
Property, plant and equipment		9,249		3,930		9,240		3,948
Unamortized energy contracts		3,171		3,171		3,218		3,218
Other intangibles, trade name and retail relationships		472		472		457		457
Investment in affiliates		1,942		1,942		1,942		1,942
Pension and OPEB regulatory asset		740		—		740		—
Other assets		2,644		1,266		2,668		1,266

Total assets		23,162		14,430		23,201		14,469

Current liabilities		3,409		2,798		3,431		2,798
Unamortized energy contracts		1,718		1,512		1,722		1,512
Long-term debt, including current maturities		6,038		2,972		6,038		2,972
Noncontrolling interest		95		95		92		92
Deferred credits and other liabilities and preferred securities		4,537		1,781		4,553		1,837

Total liabilities, preferred securities and noncontrolling interest		15,797		9,158		15,836		9,211

Total purchase price	$	7,365	$	5,272	$	7,365	$	5,258

For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the contracts were in or out-of-the-money. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts,

~~approach, which is based upon discounted projected future cash flows associated with the underlying contracts,~~ was utilized. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the merger date. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. Exelon and Generation present separately in ~~its~~their Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. Exelon amortization expense for the three months ended September 30, 2012 and for the period March 12, 2012 to September 30, 2012 were $224 million and $714 million, respectively. The weighted-average amortization period is approximately 1.5 years.

The fair value of the Constellation trade name intangible asset was determined based on the relief from royalty method of the income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The intangible assets are amortized on a straight line basis over an estimated 10 year useful life as amortization expense. The trade name intangible asset is included in deferred debits and other assets within Exelon’s and Generation’s Consolidated Balance Sheets.

The fair value of the retail relationships was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is ~~equal~~determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The intangible assets are amortized on a straight line basis over the useful life of the underlying assets averaging approximately 1212.4 years as amortization expense. The retail relationships intangible assets are included in deferred debits and other assets within Exelon’s and Generation’s Consolidated Balance Sheets.

Exelon’s intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of ~~June~~September 30, 2012:


Description	Weighted Average Amortization		Gross			Accumulated Amortization			Net				Estimated amortization expense																			Weighted Average Amortization				Gross			Accumulated Amortization			Net				Estimated amortization expense
Description	Weighted Average Amortization				Remainder of 2012							2013				2014				2015				2016							Remainder of 2012							2013							2014				2015				2016
Unamortized energy contracts, net(a)		1.5	Gross		$	Accumulated Amortization	1,453		Net	$	(489	)		$	964			$	481			$	382			$	70		$	15		Weighted Average Amortization		$	(33	Gross	)		Accumulated Amortization	1.5		Net	$	1,496			$	(714	)		$	782			$	267		$	396		$	76	$	18	$	(31	)
Trade name		10.0		243			(8	)		235				17				24				24				24			24				10.0				243			(14	)		229				10				24				24			24			24
Retail relationships		11.8		229			(7	)		222				15				23				22				21			21				12.4				214			(9	)		205				8				19				19			19			19

Total, net			$	1,925		$	(504	)	$	1,421			$	513			$	429			$	116			$	60		$	12							$	1,953		$	(737	)	$	1,216			$	285			$	439			$	119		$	61		$	12

It is impracticable to determine the current quarter and year-to-date overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation’s operations and are therefore not fully distinguishable after the merger.

The impact of BGE on Exelon’s Consolidated Statement of Operations and Comprehensive Income includes operating revenues of ~~$616~~$720 million and net income of ~~$16~~$0 million during three months ended ~~June~~September 30, 2012, and operating revenues of ~~$668~~$ 1,388 million and net loss of $49 million during the ~~six~~nine months ended ~~June~~September 30, 2012.

During the three months ended ~~June~~September 30, 2012, Exelon, Generation, PECO and BGE incurred merger and integration-related costs of ~~$111~~$87 million, ~~$94~~$79 million, $4$3 million and $2$1 million, respectively. During the ~~six~~nine months ended ~~June~~September 30, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of ~~$584~~$671 million, ~~$204~~$283 million, $2 million, ~~$11~~$13 million and ~~$154~~$155 million, respectively. These amounts do not include merger and integration-related costs of $34 million and $22 million incurred at ComEd and BGE, respectively, that have been recorded as a regulatory asset. The costs incurred are classified primarily within Operating and Maintenance Expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the ~~$113 million~~ BGE customer rate credit and the credit facility fees, which isare included as a reduction to operating revenues and other, net, respectively, for the ~~six~~nine months ended ~~June~~September 30, 2012.

During the three months ended September 30, 2011, Exelon, Generation, ComEd and PECO incurred merger and integration-related costs of $18 million, $5 million, $2 million and $1 million, respectively. During the nine months ended September 30, 2011, Exelon, Generation, ComEd and PECO incurred merger and integration-related costs of $43 million, $6 million, $2 million and $1 million, respectively. These costs are classified primarily within Operating and Maintenance Expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income.

The Registrants have an ongoing severance plan under which, in general, the longer ~~a terminated~~an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at ~~its~~ fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon recorded a pre-tax charge for estimated salary continuance, health and welfare severance benefits, and other benefits costs of $83 million in March 2012 as a result of the planned job reductions. During the three months ended June 30, 2012, Exelonhas identified specific employees to be severed pursuant to athe merger-related staffing and selection ~~process. As~~process; as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a ~~result,~~severance benefit. Exelon ~~recorded an additional pre-tax charge of $36 million~~adjusts its accrual each quarter to reflect ~~the estimated~~its best estimate of remaining severance ~~costs associated with the specifically identified employees.~~costs. The ~~estimated~~ amount of severance ~~costs~~expense associated with the post-merger integration ~~including those costs to be incurred after June~~recognized through September 30, 2012, for Exelon is ~~$121~~$130 million, which includes ~~$72~~$76 million, ~~$16~~$18 million, $7$8 million and ~~$18~~$19 million for Generation, ComEd, PECO and BGE, respectively. Estimated costs to be incurred after September 30, 2012 are not material. In addition, certain employees identified during the staffing and selection process also receive pension and other postretirement benefits that are deemed contractual termination benefits. See Note 12 —– Retirement Benefits for additional information on the contractual termination benefits.

For the three and ~~six~~nine months ended ~~June~~September 30, 2012, the Registrants recorded the following severance benefits costs associated with the identified job reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for ComEd and BGE:

Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:


Three Months Ended June 30, 2012
Three Months Ended September 30, 2012
Severance liability	Exelon			Generation		ComEd		PECO		BGE		Exelon			Generation			ComEd		PECO		BGE
Balance at March 31, 2012	$	83		$	16	$	—	$	—	$	10
Balance at June 30, 2012												$	118		$	30		$	2	$	—	$	12
Severance charges(a)		40			12		2		—		1		7			4			—		—		—
Stock compensation		(5	)		1		—		—		—		3			1			—		—		—
One-time termination benefits(b)		2			—		—		—		—		1			1			—		—		—
Other charges(c)		(1	)		1		—		—		1		—			—			—		—		—
Payments		(1	)		—		—		—		—		(9	)		(2	)		—		—		(1	)

Balance at June 30, 2012	$	118		$	30	$	2	$	—	$	12
Balance at September 30, 2012												$	120		$	34		$	2	$	—	$	11


Six Months Ended June 30, 2012
Nine Months Ended September 30, 2012
Severance liability	Exelon			Generation		ComEd		PECO		BGE		Exelon			Generation			ComEd		PECO		BGE
Balance at December 31, 2011	$	—		$	—	$	—	$	—	$	—	$	—		$	—		$	—	$	—	$	—
Severance charges(a)		107			27		2		—		11		114			31			2		—		11
Stock compensation		3			1		—		—		—		6			2			—		—		—
One-time termination benefits(b)		2			—		—		—		—		3			1			—		—		—
Other charges(c)		7			2		—		—		1		7			2			—		—		1
Payments		(1	)		—		—		—		—		(10	)		(2	)		—		—		(1	)

Balance at June 30, 2012	$	118		$	30	$	2	$	—	$	12
Balance at September 30, 2012												$	120		$	34		$	2	$	—	$	11

Cash payments under the plan began in the second quarter of 2012 and will continue through 2016. Substantially all cash payments under the plan are expected to be made by the end of ~~2016 resulting in the completion of the merger restructuring plan.~~2016.

The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon’s and Generation’s accounting policies and adjusting Constellation’s results to reflect purchase accounting adjustments.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.


	Generation				Exelon				Generation				Exelon
	Three Months Ended June 30,				Three Months Ended June 30,				Three Months Ended September 30,				Three Months Ended September 30,
	2012		2011(a)		2012		2011(b)		2012		2011(a)		2012		2011(b)
Total Revenues	$	4,051	$	4,782	$	6,256	$	7,425	$	4,293	$	5,133	$	6,841	$	8,219
Net income attributable to Exelon		397		221		528		401		282		163		492		379
Basic Earnings Per Share		n.a.		n.a.	$	0.62	$	0.47		n.a.		n.a.	$	0.58	$	0.45
Diluted Earnings Per Share		n.a.		n.a.		0.62		0.47		n.a.		n.a.		0.57		0.44

	Generation				Exelon				Generation				Exelon
	Six Months Ended June 30,				Six Months Ended June 30,				Nine Months Ended September 30,				Nine Months Ended September 30,
	2012		2011(a)		2012		2011(b)		2012		2011(a)		2012		2011(b)
Total Revenues	$	8,523	$	9,789	$	13,284	$	15,493	$	12,753	$	14,996	$	20,084	$	23,839
Net income attributable to Exelon		567		442		979		644		805		690		1,439		1,119
Basic Earnings Per Share		n.a.		n.a.	$	1.26	$	0.76		n.a.		n.a.	$	1.79	$	1.32
Diluted Earnings Per Share		n.a.		n.a.		1.25		0.76		n.a.		n.a.		1.79		1.31

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired all of the interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, Inc., which developed and will build, operate and maintain the project. On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million and terminated the put option that Generation had on the Antelope Valley project. See Note 9 -— Debt and Credit Agreements for additional information.

~~Wind~~Other Development. As part of its plan to construct multiple wind facilities in 2012, Generation has acquired several project entities. In addition, Generation has acquired solar projects and interests in oil and gas production facilities in 2012. The acquisitions are not considered material individually or in the aggregate for disclosure.

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

Except for the matters noted below, the disclosures set forth in Note 2 of the Exelon 2011 Form 10-K and Note 6 of Constellation’s and BGE’s 2011 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.

EIMA provides a structure for substantial capital investment over a ten-year period to modernize Illinois’ electric utility infrastructure. EIMA allows the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC and will provide greater certainty as to the recovery of those costs. ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million beginning in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates.

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June. On May ~~30,~~29, 2012, the ICC issued its final Order ~~(Order)~~(May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC’s determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in ~~the~~a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd’s pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 periods and for the first three months of 2012 consistent with the terms of the May Order. ~~On June 5, 2012, ComEd filed its application for rehearing with the ICC.~~

the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in ComEd’s reconciliation revenue requirement; and amending its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed an appeal of the May Order and the Rehearing Order in court on October 4, 2012. ComEd expects to record in the fourth quarter of 2012 an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order.

On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under that plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd’s historical level of capital expenditures. The filing with the ICC specifically included ComEd’s $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. On June 22, 2012, the ICC approved the AMI Deployment Plan with certain modifications. However, as a result of the Rehearing Order above, ComEd is delaying certain elements of the AMI Deployment Plan, including the delay of installation of additional smart meters. ComEd has outlined the new deployment schedule within testimony provided in the AMI Plan Rehearing on October 3, 2012. As a result of the Rehearing Order ComEd has deferred approximately $50 million of the 2012 AMI Deployment Plan and $15 million of planned capital investment to future years. An Order from the ICC on ComEd’s revised deployment plan is due by December 5, 2012.

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred (the rates will take effect in January 2013). ComEd updated its 2011 reconciliation filing on June 12, 2012 to reflect the impacts of the May Order discussed above. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of ~~June~~September 30, 2012 and December 31, 2011, ComEd recorded an estimated net regulatory asset of ~~$26~~$74 million and $84 million, respectively, which represents the ICC’s approved distribution formula and associated rulings as of ~~June~~September 30, 2012 and ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred for the twelve months ended December 31, 2011 and for the ~~six~~nine months ended ~~June~~September 30, 2012. The evidentiary hearing in ComEd’s 2011 reconciliation rate case ~~is expected to begin~~was held on September 25, 2012, ~~with~~and a final order is due by December 26, 2012.

Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. 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 post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP). The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order in the remand proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal. ComEd has recognized for accounting purposes its best estimate of any refund ~~obligation.~~obligation, as discussed above.

Advanced Metering Program Proceeding (Exelon and ComEd). In October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider ~~SMP (Rider AMP)~~AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of other costs from recovery under Rider AMP to recovery through base electric distribution rates. On March 19, 2012, the Court reversed the ICC’s approval of Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. The Illinois Supreme Court denied the Petition on September 26, 2012, and returned the matter to the ICC to calculate a refund amount. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court’s order on March 19, 2012, which would have an immaterial impact at ComEd and Exelon.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from its retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. EIMA contains a provision for the IPA to conduct procurement events for energy and REC requirements for the June 2013 through December 2017 period. The procurement events mandated under EIMA were completed during February 2012. See Note 16 — Commitments and Contingencies for additional information on ComEd’s energy commitments.

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO’s PAPUC-approved DSP Program, under which PECO is providing default electric service, has a 29-month term that began January 1, 2011 and ends May 31, 2013. Under the DSP Program, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. The filing and implementation costs of the DSP Program were recorded as a regulatory asset and are being recovered through the GSA over its 29-month term. In January and April 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, for electric supply for default electric service which included full requirements fixed price contracts for its residential, small commercial and medium commercial procurement classes that commenced in June 2012, hourly spot market price full requirements contracts for its small and medium commercial and large commercial and industrial procurement classes that commenced in June 2012 and block contracts for its residential class beginning in December 2012. In September 2012, PECO completed its last competitive procurement under the DSP Program for electric supply for default electric service. PECO entered into block contracts with PAPUC-approved bidders, including Generation, for its residential class beginning in December 2012. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations and Comprehensive Income. ~~PECO has one competitive procurement remaining over the term of this DSP Program.~~

On ~~January 13,~~October 12, 2012, ~~PECO filed~~the PAPUC issued its Opinion and Order approving PECO’s second DSP Plan, ~~for approval~~which was filed with the ~~PAPUC.~~PAPUC in January 2012. The plan, ~~outlined how PECO will purchase electricity for default customers~~which has a 24-month term from June 1, 2013 through May 31, ~~2015. To continue~~2015, complies with electric generation procurement guidelines set forth in Act 129. Under the second DSP Program, PECO is permitted to ~~ensure a competitive~~recover its electric procurement ~~process for residential~~costs from retail default service customers PECO proposed to procure electricity through a combination of one-year and two-year full requirements fixed price contracts, reduce the amount of time between when the energy is procured and when it is provided to customers and complete an annual, rather than quarterly, reconciliation of costs for actual versus forecasted energy use. The DSP Plan also proposed to eliminate the AEPS rider and recover AEPS costswithout mark-up through the GSA. ~~Hearings on~~The GSA provides for the recovery of energy, capacity, ancillary costs,

administrative costs and AEPS costs and is subject to adjustments at least quarterly for any over or under collections. The filing ~~concluded on May 22, 2012~~ and implementation costs of the DSP Program were recorded as a ~~PAPUC ruling~~regulatory asset and are being recovered through the GSA over its 24-month term.

In the second DSP plan, the load for the residential and small and medium commercial classes will be served through competitively procured contracts for fixed price, full requirements contracts of two years or less. Similar to the current DSP plan, for the large commercial and industrial class load, PECO will competitively procure contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. The first competitive procurement is expected to take place for the residential class in ~~mid-October 2012.~~December 2012 for default electric service commencing June 1, 2013.

In addition, the second DSP plan includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. In the PAPUC’s Opinion and Order, PECO was also directed to develop a plan by January 1, 2014 that will allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs. PECO expects to file its plan by March 2013.

Smart Meter and Smart Grid Investments (Exelon and PECO).~~In April 2010,~~ Pursuant to Act 129 and the follow-on Implementation Order of 2009 by the PAPUC, ~~approved PECO’s $550 million Smart Meter Procurement~~PECO began the first phase of its smart meter deployment in March 2012. The first phase calls for the installation of an AMI communications network and ~~Installation Plan under which PECO will install more than 1.6 million~~the deployment of 600,000 smart meters to communicate with that network. The first phase of smart meter deployment was estimated to cost $415 million.

Pursuant to the ARRA of 2009, PECO and ~~deploy advanced communication networks by 2020. In 2010, PECO~~the DOE entered into a Financial Assistance Agreement ~~with~~to extend PECO $200 million in SGIG funds. Of the ~~DOE for~~$200 million in grant money, $140 million is being applied to the AMI technology deployment, including 600,000 smart meters in the first phase deployment. Therefore, the SGIG funds under the ARRA of 2009. Under the SGIG, PECO was awarded $200 million, the maximum grant allowable under the program, for its SGIG project — Smart Future Greater Philadelphia. Through 2020, PECO plans to spend up to $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG isare being used to ~~reduce~~offset the impact to ratepayers of ~~these investments on PECO ratepayers.~~

the smart meter deployment required by Act 129. As of ~~June~~September 30, 2012, PECO has received ~~$119~~$130 million in reimbursements from the ~~DOE.~~DOE for its smart meter deployment and other grid improvements. PECO’s outstanding receivable from the DOE for reimbursable costs was ~~$14~~$16 million as of ~~June~~September 30, 2012, which has been recorded in other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.

On August 15, 2012, PECO suspended its installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO will replace 186,000 previously installed meters with Landis+Gyr (L+G) meters by the end of November 2012 and will use L+G meters for the remainder of the first phase deployment.

As of September 30, 2012, the carrying value of the original meters, including installation and removal costs, owned by PECO was approximately $18 million, net of approximately $16 million of reimbursements from the DOE. PECO does not expect the change in vendor to impact its eligibility for the $200 million in SGIG funds. PECO is seeking and anticipates full recovery of these meter and other incremental costs incurred in response to the overheating incidents, and, therefore, expects this matter will not have a material impact on PECO’s results of operations, cash flows or financial position.

Energy Efficiency Program (Exelon and PECO). PECO’s PAPUC-approved EE&C Plan has a four-year term that began on June 1, 2009 and sets forth how PECO will meet the various reduction targets established by Act 129’s EE&C provisions. In addition to energy consumption reductions, Act 129 requires Pennsylvania

electric distribution companies to reduce peak demand by a minimum of 4.5% of their annual system peak demand in the 100 hours of highest demand. The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a filing with the PAPUC by December 2012.

On August 2, 2012, the PAPUC issued ~~a final order regarding the next phase (Phase 2) of the~~its Phase II EE&C ~~Program.~~implementation order. The ~~final~~ order provides ~~details on~~energy consumption reduction requirements for the ~~design and implementation~~second phase of ~~Phase 2,~~Act 129 EE&C programs, which will go into effect on June 1, 2013, but defers a decision on peak demand reduction requirements until the first quarter of 2013. The order tentatively establishes PECO’s three year cumulative consumption reduction target ofat 2.9%. The order also provides the opportunity for any electric utility to challenge its proposed target in an evidentiary ~~hearing.~~hearing, which PECO ~~is evaluating these new requirements prior~~requested on August 20, 2012. In addition, on September 4, 2012, PECO filed a Petition for Reconsideration of the terms of the PAPUC’s implementation order for Phase II, which was subsequently denied.

Pursuant to ~~filing~~the Phase II implementation order, PECO filed its three year EE&C Phase II plan with the PAPUC on November 2, 2012. The plan sets forth how PECO will reduce electric consumption by at least 2.9% in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase ~~2 plan.~~II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO’s public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that that the total cost of the plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006.

Natural Gas Choice Supplier Tariff (Exelon and PECO). During 2011, the PAPUC approved PECO’s tariff supplements to its Gas Choice Supplier Coordination Tariff and its Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers (NGS) set forth in the PAPUC’s final rulemaking order,

which became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can require to mitigate its risk related to a NGS default, as well as PECO’s ability to adjust collateral when material changes in supplier creditworthiness occur. PECO has completed its creditworthiness determinations and notified affected NGSs of their new collateral levels. As a result, PECO has obtained $14 million of ~~collateral.~~collateral as of September 30, 2012.

Investigation of PA Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On ~~January 13,~~October 12, 2012, ~~PECO filed its~~the PAPUC approved PECO’s second DSP ~~for approval with the PAPUC,~~plan, which ~~proposed~~includes several new programs to continue PECO’s support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to an expiration of the electric distribution company’s current default service plan and providing guidelines for electric distribution companies for the development of their next default service plan. Further, the PAPUC issued a Secretarial Letter on September 27, 2012, outlining its proposed end-state for default service, which included short-term contracts for all default service providers of approximately 3 months and the inclusion of CAP customers in the customer choice programs. A Tentative Order on these proposals is expected to be issued in November 2012.

Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed

to recover capital project costs incurred to repair, improve or replace utilities’ ~~aging~~ electric and natural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service in future test years. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11.

2010 Natural Gas Distribution Rate Case (Exelon and PECO). PECO’s 2010 natural gas distribution rate case settlement approved by the PAPUC stipulates that the expected cash benefit resulting from the application of new tax repairs deduction methodologies for 2010 and prior tax years must be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million, for which PECO has recorded a regulatory liability that is reflected on Exelon’s and PECO’s Consolidated Balance Sheets as of September 30, 2012. This amount is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2013. The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next natural gas distribution base rate case. See Note 10 — Income Taxes for additional information.

2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs ~~will be~~are being recovered over a 5-year period ~~beginning~~which began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives. The project to install the smart meters began in late April 2012.

As of ~~June~~September 30, 2012, BGE had received ~~$114~~$126 million in reimbursements from the DOE. As of ~~June~~September 30, 2012, BGE’s outstanding receivable from the DOE for reimbursable costs was $9$13 million, which has been recorded in other accounts receivable, net on Exelon’s and BGE’s Consolidated Balance Sheets.

New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, with an assumed commercial operation date of June 1, 2015. The initial term of the proposed contract is 20 years. The CfD will provide that the utilities will pay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from bidding the unit into the PJM markets. The three Maryland utilities are required to enter into a CfD in amounts proportionate to their ~~relative SOS~~relativeSOS load as of the date of execution. Pursuant to the MDPSC’s Order, between the period of April 12, 2012 and July 6, 2012, the utilities met with CPV and the consultant for the MDPSC, Boston Pacific Company, Inc. (Boston Pacific), to negotiate changes to the CfD for submission to the MDPSC for approval. On July 10, 2012, Boston Pacific filed a revised version of the CfD with the MDPSC, along with a memorandum detailing the parties’ negotiations and the changes included in the revised CfD. BGE, the two other Maryland utilities, and other interested parties have filed written comments on the revised CfD proposed by Boston Pacific and have provided further comments at a hearing held July 31, 2012. Depending on the precise terms of the CfD, the eventual market conditions, and the manner of cost recovery, the CfD could have a material adverse impact on Exelon’s and BGE’s results of

operations, cash flows and financial positions. On April 27, 2012, a civil complaint was filed in the United States District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on federal law grounds. Among other requests for relief, the plaintiffs seek to enjoin the MDPSC from executing or otherwise putting into effect any part of its order. The MDPSC and CPV filed motions to dismiss the federal lawsuit, which ~~remain pending.~~were both denied by the U.S. District Court on August 3, 2012. On May 4, 2012, ~~BGE filed~~BGEfiled a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. That petition was subsequently transferred to the Circuit Court for Baltimore City, where similar appeals have been filed by other interested parties. ~~The two other Maryland utilities also filed petitions for judicial review in other Maryland state courts, which are also expected to~~All cases have now been consolidated and will be ~~transferred to~~heard together by the Circuit Court for Baltimore ~~City. Once transferred, it is likely that~~City in the ~~cases will be consolidated and heard together.~~first quarter of 2013.

2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases ~~of $151 million and $53 million~~ to its electric and gas base rates ~~respectively,~~ with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

Annual Transmission Formula Rate Update (Exelon, ComEd and BGE). ComEd’s most recent annual formula rate update filed in May 2012 reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. The update resulted in a revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. This compares to the May 2011 updated revenue requirement of $438 million offset by a $16 million reduction related to the reconciliation of 2010 actual costs for a net revenue requirement of $422 million. The increase in the revenue requirement was primarily driven by higher depreciation, pension and operating and maintenance costs, and the absence of a one-time credit that had been included in 2010 costs. The 2012 net revenue requirement became effective June 1, 2012 and is recovered over the period extending through May 31, 2013. The regulatory liability associated with the true-up is being amortized as the associated amounts are refunded.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.91%, a decrease from the 9.10% return for the prior year, primarily due to lower debt costs. As part of the FERC-approved settlement of ComEd’s 2007 rate case, the 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 55%.

PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit.

ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s RTEP baseline project commitments changed as of September 30, 2012 from December 31, 2011 as follows:

PJM Minimum Offer Price Rule (Exelon and Generation). PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) intended to ensure that a competitive capacity offer is based on the costs and competitive market revenues of a new entry unit. On February 1, 2011, in response to the enactment of New Jersey Senate Bill 2381, Exelon Generation joined the PJM Power Providers Group (P3) complaint at FERC seeking a revision to PJM’s MOPR to preclude the exercise of buyer market power. In response to P3’s complaint, PJM filed revisions to the MOPR which were largely approved by FERC in its April 12, 2011 Order. The revised MOPR, among other things, sets a minimum price level for sell offers for capacity from certain types of new generation resources submitted in PJM’s capacity market auctions. While a number of state regulators and consumer groups opposed the MOPR revision, the changes were in line with recent FERC orders regarding capacity markets in the New York and New England ISOs. A number of parties filed for rehearing of the FERC order. FERC generally denied rehearing, and the FERC orders have been appealed to the Third Circuit Court of Appeals. A resolution of that appeal is not expected until sometime in 2013.

In May 2012, PJM announced the results of its capacity auction covering 2015/2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. There is potential that states will expand such state-sanctioned subsidy programs or that other states may seek to establish similar programs. Exelon believes that further revisions to the MOPR may be necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~ In late September, PJM announced to all of its stakeholders that a group of its stakeholders had developed a proposal addressing the shortcomings of the current MOPR. PJM plans to have its stakeholders review and consider these proposed MOPR changes in October and November with a potential vote on these proposed MOPR changes in late November 2012. PJM would need to obtain approval from the FERC prior to implementing any changes. Exelon was actively involved in the process through which the MOPR changes were developed, supports the changes and intends to continue to work with PJM and its stakeholders to obtain necessary approvals.

~~(Dollars in millions, except per share data, unless otherwise noted)~~License Renewals (Exelon and Generation). On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project. The FERC review process is scheduled to be completed by August 31, 2014 and September 1, 2014, when the current Conowingo and Muddy Run licenses expire.

Exelon, ComEd, PECO and BGE 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.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of ~~June~~September 30, 2012 and December 31, 2011. Upon consummation of the merger, the Registrants reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of the regulated utilities. For additional information on the specific regulatory assets and liabilities, refer to Note 2 of the Exelon 2011 Form 10-K for Exelon, ComEd and PECO and Note 6 of BGE’s 2011 Form 10-K.


June 30, 2012	Exelon				ComEd				PECO					BGE
September 30, 2012																		Exelon				ComEd				PECO					BGE
	Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits(a)	$	262	$	3,476	$	—	$	—	$	3		$	—	$	2	$	—	$	264	$	3,499	$	—	$	—	$	2		$	—	$	1	$	—
Deferred income taxes		12		1,244		5		62		—			1,118		7		64		13		1,346		5		62		—			1,220		8		64
AMI and smart meter programs		2		50		2		5		—			24		—		21		2		54		2		5		—			24		—		25
Under-recovered distribution service costs		—		54		—		54		—			—		—		—		—		119		—		119		—			—		—		—
Debt costs		14		75		11		68		3			7		2		9		14		71		11		65		3			6		2		9
Fair value of BGE long-term debt(b)		48		232		—		—		—			—		—		—		43		226		—		—		—			—		—		—
Fair value of BGE supply contract(c)		110		51		—		—		—			—		—		—		94		31		—		—		—			—		—		—
Severance		29		42		25		25		—			—		4		17		30		36		25		19		—			—		5		17
Asset retirement obligations		—		77		—		53		—			24		—		—		—		84		—		59		—			25		—		—
MGP remediation costs		48		236		41		205		6			29		1		2		65		227		58		190		6			35		1		2
RTO start-up costs		3		3		3		3		—			—		—		—		3		3		3		3		—			—		—		—
Under-recovered electric universal service fund costs		9		—		—		—		9			—		—		—		8		—		—		—		8			—		—		—
Financial swap with Generation		—		—		506		—		—			—		—		—		—		—		352		—		—			—		—		—
Renewable energy and associated RECs		19		92		19		92		—			—		—		—		17		53		17		53		—			—		—		—
Under-recovered energy and transmission costs		151		—		101		—		10	(d)		—		40		—		62		—		22		—		7	(d)		—		33		—
DSP Program costs		2		2		—		—		2			2		—		—		2		2		—		—		2			2		—		—
DSP II Program costs																			—		2		—		—		—			2		—		—
Deferred storm costs		3		8		—		—		—			—		3		8		3		7		—		—		—			—		3		7
Electric generation-related regulatory asset		16		48		—		—		—			—		16		48		16		44		—		—		—			—		16		44
Rate stabilization deferral		65		269		—		—		—			—		65		269		65		244		—		—		—			—		65		244
Energy efficiency and demand response programs		39		108		—		—		—			—		39		108		55		117		—		—		—			—		55		117
Other		35		36		13		16		21			12		—		4		30		27		16		14		14			9		—		5

Total regulatory assets	$	867		6,103	$	726	$	583	$	54		$	1,216	$	179	$	550	$	786		6,192	$	511	$	589	$	42		$	1,323	$	189	$	534


June 30, 2012	Exelon				ComEd				PECO					BGE
September 30, 2012																		Exelon				ComEd				PECO					BGE
	Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Regulatory liabilities
Nuclear decommissioning	$	—	$	2,352	$	—	$	1,960	$	—		$	392	$	—	$	—	$	—	$	2,383	$	—	$	2,021	$	—		$	362	$	—	$	—
Removal costs		87		1,397		65		1,189		—			—		22		208		94		1,397		73		1,185		—			—		21		212
Energy efficiency and demand response programs		31		72		19		—		12			72		—		—		82		33		37		—		45			33		—		—
Electric distribution tax repairs		19		142		—		—		19			142		—		—		18		138		—		—		18			138		—		—
Gas distribution tax repairs																			5		49						5			49
Over-recovered distribution service costs		28		—		28		—		—			—		—		—		45		—		45		—		—			—		—		—
Over-recovered uncollectible accounts		27		—		27		—		—			—		—		—		10		—		10		—		—			—		—		—
Over-recovered energy and transmission costs		60		—		7		—		53	(e)		—		—		—		39		—		7		—		32	(e)		—		—		—
Over-recovered gas universal service fund costs		3		—		—		—		3			—		—		—		3		—		—		—		3			—		—		—
Over-recovered AEPS costs		4		—		—		—		4			—		—		—		1		—		—		—		1			—		—		—
Customer rate credit																			1		—		—		—		—			—		1		—
Other																			1		—		—		—		1			—		—		—

Total regulatory liabilities	$	259	$	3,963	$	146	$	3,149	$	91		$	606	$	22	$	208	$	299	$	4,000	$	172	$	3,206	$	105		$	582	$	22	$	212

ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities’ consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Purchased receivables are classified in other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of ~~June~~September 30, 2012 and December 31, 2011.


As of September 30, 2012												Exelon			ComEd			PECO			BGE
Purchased receivables(a)												$	203		$	56		$	72		$	75
Allowance for uncollectible accounts(b)													(18	)		(6	)		(7	)		(5	)

Purchased receivables, net												$	185		$	50		$	65		$	70


As of December 31, 2011	Exelon			ComEd		PECO			BGE			Exelon			ComEd			PECO			BGE
Purchased receivables(a)	$	68		$	16	$	52		$	61		$	68		$	16		$	52		$	61
Allowance for uncollectible accounts(b)		(5	)		—		(5	)		(3	)		(5	)		—			(5	)		(3	)

Purchased receivables, net	$	63		$	16	$	47		$	58		$	63		$	16		$	47		$	58

5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation’s total equity in earnings (losses) on the investment in CENG is as follows:

As of March 12, 2012, Generation had an initial basis difference of approximately ~~$198~~$204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG.

In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Generation would record these distributions, if realized, in earnings in the period earned.

A subsidiary of Generation has an agreement ~~with CENG~~ under which it is purchasing 85-90% of the output of CENG’s nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG’s nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.

In addition to the PPA, a subsidiary of Generation has a power services agency agreement (PSAA) with ~~CENG.~~the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and

billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the service, with such cost not to exceed approximately $358,000 per month.

In addition to the PSAA, Exelon has ~~an administrative~~a shared services agreement ~~(ASA)~~(SSA) with CENG, which expires in 2017. Under the ~~ASA,~~SSA, BSC provides a variety of support services to CENG. The ~~ASA~~SSA includes both a consumption-based pricing structure and a fixed-price structure which are subject to change in future years based on the level of service needed. Pursuant to an agreement between Exelon and EDF, the pricing in the ~~ASA~~SSA is in the process of being amended so that the charges for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.

The impact of transactions under these agreements on Exelon’s and Generation’s Consolidated Financial Statements is summarized below:

In May 2011, CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount of ~~$62.5~~$63 million from a subsidiary of Generation. CENG also issued a promissory note to EDF on substantially identical terms, such that any request for borrowings by CENG must be submitted ~~50.01%~~50% to Generation and ~~49.99%~~50% to EDF.

Interest accrues on the amounts borrowed on a daily basis at a rate of LIBOR, plus 250 basis points. Amounts are due at the earlier of October 31, 2012 or the date upon which the note is accelerated in accordance with the terms of the agreement.

As of ~~June~~September 30, 2012, CENG had borrowed ~~$55~~$43 million from Generation. The unsecured promissory note matured on October 31, 2012, and all amounts due were paid in full as of that date.

Under the authoritative guidance for the accounting for goodwill, ComEd is required to perform an assessment for possible impairment of its goodwill at least annually or more frequently if an event occurs, such as a significant negative regulatory outcome, that would more likely than not reduce the fair value of the ComEd

reporting unit below its carrying amount. In May 2012, the ICC issued a final Order (Order) in ComEd’s 2011 formula rate proceeding under the EIMA that reduced ComEd’s annual revenue requirement being recovered in current rates by $168 million. ~~See Note 4 — Regulatory Matters for further detail.~~ Management concluded that the Order represents an event that required an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of May 31, 2012.

The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. Consistent with the annual impairment test, the estimated fair value of ComEd was determined using a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash

flow analysis relies on a single scenario reflecting “base case” or management’s best estimate of projected cash flows for ComEd’s business. In performing the discounted cash flow analysis for the interim goodwill test, management assumed that ComEd would ultimately prevail in appealing certain aspects of the Order, specifically the return on ComEd’s pension asset and the use of year-end rate base in determining ComEd’s annual revenue requirement being recovered in current rates. The disallowances related to the pension asset return and year-end rate base are estimated to reduce ComEd’s revenue requirement recovered in rates by approximately $75 – $130 million annually. The assessment also reflects several favorable changes in certain market assumptions since the annual impairment assessment in 2011, including the weighted average cost of capital and market multiples.

Based on the results of the interim goodwill test, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test.

On October 3, 2012, the ICC issued its Rehearing Order in response to ComEd’s expedited rehearing request. The Rehearing Order adopted ComEd’s position on the return on its pension asset resulting in an increase in ComEd’s annual revenue requirement. See Note 4 — Regulatory Matters for further detail.

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

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation and preferred securities as of ~~June~~September 30, 2012 and December 31, 2011:


	June 30, 2012													December 31, 2011							September 30, 2012												December 31, 2011
	Carrying Amount				Fair Value									Carrying Amount			Fair Value				Carrying Amount			Fair Value									Carrying Amount			Fair Value
				Level 1				Level 2			Level 3			Carrying Amount						Level 1					Level 2			Level 3					Carrying Amount			Fair Value
Short-term liabilities	Carrying Amount	$	178			$	—		$	178		$	—		$	—	Fair Value		$	—	Carrying Amount		$	289		$	4		$	285		$	—		$	737		$	737
Long-term debt (including amounts due within one year)		5,216				—			6,174			18			5,665			6,540				18,715			—			20,762			38			12,627			14,488
Long-term debt to financing trust		206				—			208			—			206			184
Long-term debt to financing trusts																						649			—			650			—			390			358
SNF obligation																						1,020			—			780			—			1,019			886
Preferred securities of subsidiary																						87			—			83			—			87			79


	June 30, 2012								December 31, 2011							September 30, 2012												December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount			Fair Value				Carrying Amount			Fair Value									Carrying Amount			Fair Value
	Carrying Amount		Level 1		Level 2		Level 3								Level 1					Level 2			Level 3					Carrying Amount			Fair Value
Short-term liabilities	$	225	$	—	$	225	$	—	Carrying Amount	$	225	Fair Value		$	225	Carrying Amount		$	225		$	—		$	225		$	—		$	225		$	225
Long-term debt (including amounts due within one year)		1,973		—		2,307		—		1,972			2,295				2,322			—			2,682			—			1,972			2,295
Long-term debt to financing trusts		184		—		180		—		184			174				184			—			180			—			184			174
Preferred securities		87		—		82		—		87			79				87			—			83			—			87			79


	June 30, 2012													December 31, 2011						September 30, 2012								December 31, 2011
	Carrying Amount				Fair Value									Carrying Amount			Fair Value			Carrying Amount		Fair Value						Carrying Amount		Fair Value
				Level 1				Level 2			Level 3			Carrying Amount					Level 1				Level 2		Level 3			Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	Carrying Amount		1,961				—			2,270			—			2,101	Fair Value		2,377	Carrying Amount		2,210		—		2,547		—		2,101		2,377
Long-term debt to financing trusts		258				—			264			—			258			256			258		—		264		—		258		256

Short-Term Liabilities. The short-term liabilities included in the ~~table~~tables above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO’s accounts receivable agreement (Level 2), and dividends payable (Level 1). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments. See Note 9 — Debt and Credit Agreements for additional information on PECO’s accounts receivable agreement.

Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current

market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

The Registrants also have tax-exempt debt. Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (i.e., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above.

SNF Obligation. The carrying amount of Generation’s SNF obligation is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation in ~~2020~~2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of ~~2020.~~2025.

Preferred Securities of Subsidiary, Long-Term Debt to Financing Trusts and Junior Subordinated Debentures. The fair value of these securities is determined using observable market prices on the last trade date of the quarter as these securities are actively traded, less accrued interest. The securities are registered with the SEC and are public.

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

There were no transfers between Level 1 and Level 2 during the ~~six~~nine months ended ~~June~~September 30, 2012.

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 ~~June~~September 30, 2012 and December 31, 2011:


As of June 30, 2012	Level 1		Level 2		Level 3		Total
As of September 30, 2012									Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	936	$	—	$	—	$	936	$	1,117	$	—	$	—	$	1,117
Nuclear decommissioning trust fund investments
Cash equivalents		320		—		—		320		319		—		—		319
Equity
Equity securities		1,362		—		—		1,362		1,452		—		—		1,452
Commingled funds		—		1,798		—		1,798		—		1,906		—		1,906

Equity funds subtotal		1,362		1,798		—		3,160		1,452		1,906		—		3,358

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,115		—		—		1,115		1,100		—		—		1,100
Debt securities issued by states of the United States and political subdivisions of the states		—		342		—		342		—		355		—		355
Debt securities issued by foreign governments		—		73		—		73		—		84		—		84
Corporate debt securities		—		1,631		—		1,631		—		1,734		—		1,734
Federal agency mortgage-backed securities		—		43		—		43		—		31		—		31
Commercial mortgage-backed securities (non-agency)		—		39		—		39		—		47		—		47
Residential mortgage-backed securities (non-agency)		—		12		—		12		—		15		—		15
Mutual funds		—		8		—		8		—		9		—		9

Fixed income subtotal		1,115		2,148		—		3,263		1,100		2,275		—		3,375

Direct lending securities		—		—		54		54		—		—		70		70
Other debt obligations		—		14		—		14		—		16		—		16

Nuclear decommissioning trust fund investments subtotal(b)		2,797		3,960		54		6,811		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		20		—		—		20		21		—		—		21
Commingled funds		—		18		—		18		—		20		—		20

Equity funds subtotal		20		18		—		38		21		20		—		41

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		79		17		—		96		78		15		—		93
Debt securities issued by states of the United States and political subdivisions of the states		—		60		—		60		—		58		—		58
Corporate debt securities		—		278		—		278		—		260		—		260
Federal agency mortgage-backed securities		—		83		—		83		—		60		—		60
Commercial mortgage-backed securities (non-agency)		—		7		—		7		—		6		—		6
Commingled funds		—		28		—		28		—		43		—		43

Fixed income subtotal		79		473		—		552		78		442		—		520

Direct lending securities		—		—		59		59		—		—		64		64
Other debt obligations		—		1		—		1		—		1		—		1

Pledged assets for Zion Station decommissioning subtotal(c)		99		492		59		650		99		463		64		626


As of June 30, 2012	Level 1			Level 2			Level 3			Total
As of September 30, 2012													Level 1			Level 2			Level 3			Total
Rabbi trust investments
Cash equivalents		2			—			—			2			2			—			—			2
Mutual funds(d)(e)		72			—			—			72			69			—			—			69

Rabbi trust investments subtotal		74			—			—			74			71			—			—			71

Commodity mark-to-market derivative assets
Economic hedges		1,414			5,425			821			7,660			994			3,872			666			5,532
Proprietary trading		2,121			4,720			183			7,024			1,631			3,070			140			4,841
Effect of netting and allocation of collateral(f)		(3,710	)		(8,423	)		(261	)		(12,394	)		(2,597	)		(5,695	)		(238	)		(8,530	)

Commodity mark-to-market assets subtotal(g)		(175	)		1,722			743			2,290			28			1,247			568			1,843

Interest rate mark-to-market derivative assets		—			120			—			120			—			125			—			125

Other investments		2			—			17			19			2			—			17			19

Total assets		3,733			6,294			873			10,900			4,188			6,032			719			10,939

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,807	)		(4,194	)		(418	)		(6,419	)		(1,225	)		(2,814	)		(351	)		(4,390	)
Proprietary trading		(2,171	)		(4,500	)		(298	)		(6,969	)		(1,678	)		(2,881	)		(222	)		(4,781	)
Effect of netting and allocation of collateral(f)		3,978			7,825			268			12,071			2,772			5,336			229			8,337

Commodity mark-to-market liabilities subtotal(g)(h)		—			(869	)		(448	)		(1,317	)		(131	)		(359	)		(344	)		(834	)

Interest rate mark-to-market derivative liabilities		—			(89	)		—			(89	)		—			(95	)		—			(95	)

Deferred compensation		—			(97	)		—			(97	)		—			(101	)		—			(101	)

Total liabilities		—			(1,055	)		(448	)		(1,503	)		(131	)		(555	)		(344	)		(1,030	)

Total net assets	$	3,733		$	5,239		$	425		$	9,397		$	4,057		$	5,477		$	375		$	9,909


As of December 31, 2011	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	861		$	—		$	—		$	861
Nuclear decommissioning trust fund investments
Cash equivalents		562			—			—			562
Equity
Equity securities		1,275			—			—			1,275
Commingled funds		—			1,822			—			1,822

Equity funds subtotal		1,275			1,822			—			3,097

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,014			33			—			1,047
Debt securities issued by states of the United States and political subdivisions of the states		—			541			—			541
Debt securities issued by foreign governments		—			16			—			16
Corporate debt securities		—			778			—			778
Federal agency mortgage-backed securities		—			357			—			357
Commercial mortgage-backed securities (non-agency)		—			83			—			83
Residential mortgage-backed securities (non-agency)		—			5			—			5
Mutual funds		—			47			—			47

Fixed income subtotal		1,014			1,860			—			2,874

Direct lending securities		—			—			13			13
Other debt obligations		—			18			—			18

Nuclear decommissioning trust fund investments subtotal(b)		2,851			3,700			13			6,564


As of December 31, 2011	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Direct lending securities														—			—			13			13
Other debt obligations														—			18			—			18

Nuclear decommissioning trust fund investments subtotal(b)														2,851			3,700			13			6,564

Pledged assets for Zion decommissioning
Equity
Equity securities		35			—			—			35			35			—			—			35
Commingled funds		—			30			—			30			—			30			—			30

Equity funds subtotal		35			30			—			65			35			30			—			65

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		54			26			—			80			54			26			—			80
Debt securities issued by states of the United States and political subdivisions of the states		—			65			—			65			—			65			—			65
Corporate debt securities		—			314			—			314			—			314			—			314
Federal agency mortgage-backed securities		—			121			—			121			—			121			—			121
Commercial mortgage-backed securities (non-agency)		—			10			—			10			—			10			—			10
Commingled funds		—			20			—			20			—			20			—			20

Fixed income subtotal		54			556			—			610			54			556			—			610

Direct lending securities		—			—			37			37			—			—			37			37
Other debt obligations		—			13			—			13			—			13			—			13

Pledged assets for Zion Station decommissioning subtotal(c)		89			599			37			725			89			599			37			725

Rabbi trust investments
Cash equivalents		2			—			—			2			2			—			—			2
Mutual funds(d)(e)		34			—			—			34			34			—			—			34

Rabbi trust investments subtotal		36			—			—			36			36			—			—			36

Commodity mark-to-market derivative assets
Cash flow hedges		—			857			—			857			—			857			—			857
Economic hedges		—			1,653			124			1,777			—			1,653			124			1,777
Proprietary trading		—			240			48			288			—			240			48			288
Effect of netting and allocation of collateral(f)		—			(1,827	)		(28	)		(1,855	)		—			(1,827	)		(28	)		(1,855	)

Commodity mark-to-market assets(g)		—			923			144			1,067			—			923			144			1,067

Interest rate mark-to-market derivative assets		—			15			—			15			—			15			—			15

Total assets		3,837			5,237			194			9,268			3,837			5,237			194			9,268

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		—			(13	)		—			(13	)		—			(13	)		—			(13	)
Economic hedges		(1	)		(1,137	)		(119	)		(1,257	)		(1	)		(1,137	)		(119	)		(1,257	)
Proprietary trading		—			(236	)		(28	)		(264	)		—			(236	)		(28	)		(264	)
Effect of netting and allocation of collateral(f)		—			1,295			20			1,315			—			1,295			20			1,315

Commodity mark-to-market liabilities(h)		(1	)		(91	)		(127	)		(219	)
Commodity mark-to-market liabilities (h)														(1	)		(91	)		(127	)		(219	)

Interest rate mark-to-market liabilities		—			(19	)		—			(19	)		—			(19	)		—			(19	)

Deferred compensation		—			(73	)		—			(73	)		—			(73	)		—			(73	)

Total liabilities		(1	)		(183	)		(127	)		(311	)		(1	)		(183	)		(127	)		(311	)

Total net assets	$	3,836		$	5,054		$	67		$	8,957		$	3,836		$	5,054		$	67		$	8,957

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


Six Months Ended June 30, 2012	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Other Investments		Total
Nine Months Ended September 30, 2012														Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives			Other Investments		Total
Balance as of December 31, 2011	$	13	$	37		$	17		$	—	$	67		$	13	$	37		$	17		$	—	$	67
Total realized / unrealized
Total realized / unrealized gains (losses)
Included in net income		—		—			18	(a)		—		18			—		—			(157	)(a)		—		(157	)
Included in other comprehensive income		—		—			—			—		—			—		—			1			—		1
Included in regulatory assets		—		—			(5	)(b)		—		(5	)		2		—			36	(b)		—		38
Included in payable for Zion Station decommissioning		—		(1	)		—			—		(1	)
Change in collateral		—		—			(19	)		—		(19	)		—		—			(7	)		—		(7	)
Purchases, sales, issuances and settlements
Purchases		41		32			316	(c)		17		406
Purchases(c)															55		36			329			17		437
Sales		—		(9	)		—			—		(9	)		—		(9	)		—			—		(9	)
Transfers into Level 3		—		—			(34	)		—		(34	)		—		—			(34	)		—		(34	)
Transfers out of Level 3		—		—			2			—		2			—		—			39			—		39

Balance as of June 30, 2012	$	54	$	59		$	295		$	17	$	425
Balance as of September 30, 2012														$	70	$	64		$	224		$	17	$	375

The amount of total gains included in income attributed to the change in unrealized losses related to assets and liabilities held for the six months ended June 30, 2012	$	—	$	—		$	103		$	—	$	103
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012														$	—	$	—		$	(16	)	$	—	$	(16	)


Three Months Ended June 30, 2011	Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Total
Balance as of March 31, 2011	$	31		$	51		$	82
Three Months Ended September 30, 2011										Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Total
Balance as of June 30, 2011										$	—	$	34		$	(16	)	$	18
Total realized / unrealized gains (losses)
Included in income		—			21	(a)		21			—		—			(8	)(a)		(8	)
Included in other comprehensive income		—			(3	)(b)		(3	)		—		—			(15	)(b)		(15	)
Included in regulatory assets					(85	)		(85	)		—		—			(18	)		(18	)
Included in payable for Zion Station decommissioning		3			—			3			—		(3	)		—			(3	)
Change in collateral		—			2			2			—		—			8			8
Purchases, sales, issuances and settlements
Purchases		12			5			17			6		17			—			23
Sales		(12	)		—			(12	)		—		(10	)		—			(10	)
Transfers out of Level 3 — Asset		—			(7	)		(7	)
Transfers out of Level 3											—		—			24			24

Balance as of June 30, 2011	$	34		$	(16	)	$	18
Balance as of September 30, 2011										$	6	$	38		$	(25	)	$	19

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2011	$	—		$	30		$	30
The amount of total gains included in income attributed to the change in unrealized losses related to assets and liabilities held for the three months ended September 30, 2011										$	—	$	—		$	(5	)	$	(5	)


Six Months Ended June 30, 2011	Pledged Assets for Zion Decommissioning			Mark-to-Market Derivatives			Total
Nine Months Ended September 30, 2011										Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Decommissioning			Mark-to-Market Derivatives			Total
Balance as of December 31, 2010	$	—		$	50		$	50		$	—	$	—		$	50		$	50
Total realized / unrealized gains (losses)
Included in income		—			8	(a)		8
Included in other comprehensive income		—			(12	)(b)		(12	)		—		—			(27	)(a)		(27	)
Included in regulatory assets		—			(33	)		(33	)		—		—			(51	)(b)		(51	)
Included in payable for Zion Station decommissioning		3			—			3
Change in collateral		—			7			7			—		—			15			15
Purchases, sales, issuances and settlements
Purchases		43			5			48			6		60			4			70
Sales		(12	)		—			(12	)		—		(22	)		—			(22	)
Transfers out of Level 3 — Asset		—			(41	)		(41	)
Transfers out of Level 3											—		—			(16	)		(16	)

Balance as of June 30, 2011	$	34		$	(16	)	$	18
Balance as of September 30, 2011										$	6	$	38		$	(25	)	$	19

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2011	$	—		$	23		$	23
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2011										$	—	$	—		$	18		$	18

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:

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 ~~June~~September 30, 2012 and December 31, 2011:


As of June 30, 2012	Level 1		Level 2		Level 3		Total
As of September 30, 2012									Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	706	$	—	$	—	$	706	$	518	$	—	$	—	$	518
Nuclear decommissioning trust fund investments
Cash equivalents		320		—		—		320		319		—		—		319
Equity
Equity securities		1,362		—		—		1,362		1,452		—		—		1,452
Commingled funds		—		1,798		—		1,798		—		1,906		—		1,906

Equity funds subtotal		1,362		1,798		—		3,160		1,452		1,906		—		3,358

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,115		—		—		1,115		1,100		—		—		1,100
Debt securities issued by states of the United States and political subdivisions of the states		—		342		—		342		—		355		—		355
Debt securities issued by foreign governments		—		73		—		73		—		84		—		84
Corporate debt securities		—		1,631		—		1,631		—		1,734		—		1,734
Federal agency mortgage-backed securities		—		43		—		43		—		31		—		31
Commercial mortgage-backed securities (non-agency)		—		39		—		39		—		47		—		47
Residential mortgage-backed securities (non-agency)		—		12		—		12		—		15		—		15
Mutual funds		—		8		—		8		—		9		—		9

Fixed income subtotal		1,115		2,148		—		3,263		1,100		2,275		—		3,375

Direct lending securities		—		—		54		54		—		—		70		70
Other debt obligations		—		14		—		14		—		16		—		16

Nuclear decommissioning trust fund investments subtotal(b)		2,797		3,960		54		6,811		2,871		4,197		70		7,138

Pledged assets for Zion Station decommissioning
Equity
Equity securities		20		—		—		20		21		—		—		21
Commingled funds		—		18		—		18		—		20		—		20

Equity funds subtotal		20		18		—		38		21		20		—		41

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		79		17		—		96		78		15		—		93
Debt securities issued by states of the United States and political subdivisions of the states		—		60		—		60		—		58		—		58
Corporate debt securities		—		278		—		278		—		260		—		260
Federal agency mortgage-backed securities		—		83		—		83		—		60		—		60
Commercial mortgage-backed securities (non-agency)		—		7		—		7		—		6		—		6
Commingled funds		—		28		—		28		—		43		—		43

Fixed income subtotal		79		473		—		552		78		442		—		520

Direct lending securities		—		—		59		59		—		—		64		64
Other debt obligations		—		1		—		1		—		1		—		1

Pledged assets for Zion Station decommissioning subtotal(c)		99		492		59		650


As of June 30, 2012	Level 1			Level 2			Level 3			Total
As of September 30, 2012													Level 1			Level 2			Level 3			Total
Pledged assets for Zion Station decommissioning subtotal(c)														99			463			64			626

Rabbi trust investments
Cash equivalents		1			—			—			1			1			—			—			1
Mutual funds(d)(e)		12			—			—			12			13			—			—			13

Rabbi trust investments subtotal		13			—			—			13			14			—			—			14

Commodity mark-to-market derivative assets
Economic hedges		1,414			5,425			1,327			8,166			994			3,872			1,018			5,884
Proprietary trading		2,121			4,720			183			7,024			1,631			3,070			140			4,841
Effect of netting and allocation of collateral(f)		(3,710	)		(8,423	)		(261	)		(12,394	)		(2,597	)		(5,695	)		(238	)		(8,530	)

Commodity mark-to-market assets subtotal(g)		(175	)		1,722			1,249			2,796			28			1,247			920			2,195

Interest Rate mark-to-market derivative assets		—			107			—			107			—			111			—			111

Other investments		2			—			17			19			2			—			17			19

Total assets		3,442			6,281			1,379			11,102			3,532			6,018			1,071			10,621

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,807	)		(4,194	)		(307	)		(6,308	)		(1,225	)		(2,814	)		(281	)		(4,320	)
Proprietary trading		(2,171	)		(4,500	)		(298	)		(6,969	)		(1,678	)		(2,881	)		(222	)		(4,781	)
Effect of netting and allocation of collateral(f)		3,978			7,825			268			12,071			2,772			5,336			229			8,337

Commodity mark-to-market liabilities subtotal		—			(869	)		(337	)		(1,206	)		(131	)		(359	)		(274	)		(764	)

Interest rate mark-to-market derivative liabilities		—			(89	)		—			(89	)		—			(95	)		—			(95	)

Deferred compensation		—			(25	)		—			(25	)		—			(27	)		—			(27	)

Total liabilities		—			(983	)		(337	)		(1,320	)		(131	)		(481	)		(274	)		(886	)

Total net assets	$	3,442		$	5,298		$	1,042		$	9,782		$	3,401		$	5,537		$	797		$	9,735


As of December 31, 2011	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	466		$	—		$	—		$	466
Nuclear decommissioning trust fund investments
Cash equivalents		562			—			—			562
Equity
Equity securities		1,275			—			—			1,275
Commingled funds		—			1,822			—			1,822

Equity funds subtotal		1,275			1,822			—			3,097

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,014			33			—			1,047
Debt securities issued by states of the United States and political subdivisions of the states		—			541			—			541
Debt securities issued by foreign governments		—			16			—			16
Corporate debt securities		—			778			—			778
Federal agency mortgage-backed securities		—			357			—			357
Commercial mortgage-backed securities (non-agency)		—			83			—			83
Residential mortgage-backed securities (non-agency)		—			5			—			5
Mutual funds		—			47			—			47

Fixed income subtotal		1,014			1,860			—			2,874

Direct lending securities		—			—			13			13
Other debt obligations		—			18			—			18

Nuclear decommissioning trust fund investments subtotal(b)		2,851			3,700			13			6,564


As of December 31, 2011	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Fixed income subtotal														1,014			1,860			—			2,874

Direct lending securities														—			—			13			13
Other debt obligations														—			18			—			18

Nuclear decommissioning trust fund investments subtotal(b)														2,851			3,700			13			6,564

Pledged assets for Zion Station decommissioning
Equity
Equity securities		35			—			—			35			35			—			—			35
Commingled funds		—			30			—			30			—			30			—			30

Equity funds subtotal		35			30			—			65			35			30			—			65

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		54			26			—			80			54			26			—			80
Debt securities issued by states of the United States and political subdivisions of the states		—			65			—			65			—			65			—			65
Corporate debt securities		—			314			—			314			—			314			—			314
Federal agency mortgage-backed securities		—			121			—			121			—			121			—			121
Commercial mortgage-backed securities (non-agency)		—			10			—			10			—			10			—			10
Commingled funds		—			20			—			20			—			20			—			20

Fixed income subtotal		54			556			—			610			54			556			—			610

Direct lending securities		—			—			37			37			—			—			37			37
Other debt obligations		—			13			—			13			—			13			—			13

Pledged assets for Zion Station decommissioning subtotal(c)		89			599			37			725			89			599			37			725

Rabbi trust investments(d)(e)		4			—			—			4			4			—			—			4
Commodity mark-to-market derivative assets
Cash flow hedges		—			857			694			1,551			—			857			694			1,551
Other derivatives		—			1,653			124			1,777			—			1,653			124			1,777
Proprietary trading		—			240			48			288			—			240			48			288
Effect of netting and allocation of collateral(f)		—			(1,827	)		(28	)		(1,855	)		—			(1,827	)		(28	)		(1,855	)

Commodity mark-to-market assets subtotal(g)		—			923			838			1,761			—			923			838			1,761

Total assets		3,410			5,222			888			9,520			3,410			5,222			888			9,520

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		—			(13	)		—			(13	)		—			(13	)		—			(13	)
Other derivatives		(1	)		(1,137	)		(13	)		(1,151	)		(1	)		(1,137	)		(13	)		(1,151	)
Proprietary trading		—			(236	)		(28	)		(264	)		—			(236	)		(28	)		(264	)
Effect of netting and allocation of collateral(f)		—			1,295			20			1,315			—			1,295			20			1,315

Commodity mark-to-market liabilities subtotal		(1	)		(91	)		(21	)		(113	)		(1	)		(91	)		(21	)		(113	)

Interest rate mark-to-market derivative liabilities		—			(19	)		—			(19	)		—			(19	)		—			(19	)

Deferred compensation		—			(18	)		—			(18	)		—			(18	)		—			(18	)

Total liabilities		(1	)		(128	)		(21	)		(150	)		(1	)		(128	)		(21	)		(150	)

Total net assets	$	3,409		$	5,094		$	867		$	9,370		$	3,409		$	5,094		$	867		$	9,370

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 ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


Three Months Ended June 30, 2012	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2012	$	13	$	42		$	1,182			14	$	1,251
Three Months Ended September 30, 2012														Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of June 30, 2012														$	54	$	59	$	912			17	$	1,042
Total unrealized / realized gains (losses)
Included in income		—		—			(71	)(a)		—		(71	)		—		—		(112	)(a)		—		(112	)
Included in other comprehensive income		—		—			(172	)(b)		—		(172	)		—		—		(139	)(b)		—		(139	)
Included in noncurrent payables to affiliates															2		—		—			—		2
Included in payable for Zion Station decommissioning		—		(1	)		—			—		(1	)		—		1		—			—		1
Change in collateral		—		—			4			—		4			—		—		(15	)		—		(15	)
Purchases, sales, issuances and settlements
Purchases(c)		41		26			—			3		70			14		4		—			—		18
Sales		—		(8	)		—			—		(8	)
Transfers into Level 3		—		—			(34	)
Transfers out of Level 3		—		—			3			—		3

Balance as of June 30, 2012	$	54	$	59		$	912		$	17	$	1,042
Balance as of September 30, 2012														$	70	$	64	$	646		$	17	$	797

The amount of total losses included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2012	$	—	$	—		$	(15	)	$	—	$	(15	)
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2012														$	—	$	—	$	(77	)	$	—	$	(77	)


Six Months Ended June 30, 2012	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Other Investments		Total

Nine Months Ended September 30, 2012														Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2011	$	13	$	37		$	817			—	$	867		$	13	$	37		$	817			—	$	867
Total unrealized / realized gains (losses)
Included in income		—		—			3	(a)		—		3			—		—			(187	)(a)		—		(187	)
Included in other comprehensive income		—		—			(173	)(b)		—		(173	)		—		—			(311	)(b)		—		(311	)
Included in payable for Zion Station decommissioning		—		(1	)		—			—		(1	)
Included in noncurrent payables to affiliates															2		—			—			—		2
Change in collateral		—		—			(19	)		—		(19	)		—		—			(7	)		—		(7	)
Purchases, sales, issuances and settlements
Purchases(c)		41		32			316			17		406			55		36			329			17		437
Sales		—		(9	)		—			—		(9	)		—		(9	)		—			—		(9	)
Transfers into Level 3		—		—			(34	)							—		—			(34	)				(34	)
Transfers out of Level 3		—		—			2			—		2			—		—			39			—		39

Balance as of June 30, 2012	$	54	$	59		$	912		$	17	$	1,042
Balance as of September 30, 2012														$	70	$	64		$	646		$	17	$	797

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2012	$	—	$	—		$	78		$	—	$	78
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2012														$	—	$	—		$	(77	)	$	—	$	(77	)


Three Months Ended June 30, 2011	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of March 31, 2011	$	31		$	933		$	964
Total realized / unrealized losses
Three Months Ended September 30, 2011										Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Total
Balance as of June 30, 2011										$	—	$	34		$	776		$	810
Total realized / unrealized gains (losses)
Included in income		—			21	(a)		21			—		—			(8	)(a)		(8	)
Included in other comprehensive income		—			(178	)(b)		(178	)		—		—			(110	)(b)		(110	)
Included in payable for Zion Station decommissioning		3			—			3			—		(3	)		—			(3	)
Changes in collateral		—			2			2			—		—			8			8
Purchases, sales, issuances and settlements
Purchases		12			5			17			6		17			—			23
Sales		(12	)		—			(12	)		—		(10	)		—			(10	)
Transfers out of Level 3 — Asset		—			(7	)		(7	)		—		—			24			24

Balance as of June 30, 2011	$	34		$	776		$	810
Balance as of September 30, 2011										$	6	$	38		$	690		$	734

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2011	$	—		$	30		$	30
The amount of total gains included in income attributed to the change in unrealized (losses) related to assets and liabilities held for the three months ended September 30, 2011										$	—	$	—		$	(5	)	$	(5	)

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 ~~June~~September 30, 2012 and December 31, 2011:


As of September 30, 2012												Level 1		Level 2			Level 3			Total
Assets
Rabbi trust investments
Mutual funds													9		—			—			9

Rabbi trust investment subtotal													9		—			—			9

Total assets													9		—			—			9

Liabilities
Deferred compensation obligation													—		(9	)		—			(9	)
Mark-to-market derivative liabilities(b)(c)													—		—			(422	)		(422	)

Total liabilities													—		(9	)		(422	)		(431	)

Total net assets (liabilities)												$	9	$	(9	)	$	(422	)	$	(422	)


As of December 31, 2011	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	173	$	—		$	—		$	173		$	173	$	—		$	—		$	173
Rabbi trust investments
Cash equivalents		2		—			—			2			2		—			—			2
Mutual funds		19		—			—			19			19		—			—			19

Rabbi trust investment subtotal		21		—			—			21			21		—			—			21

Total assets		194		—			—			194			194		—			—			194

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)		—		(8	)		—			(8	)
Mark-to-market derivative liabilities(b)(c)		—		—			(800	)		(800	)		—		—			(800	)		(800	)

Total liabilities		—		(8	)		(800	)		(808	)		—		(8	)		(800	)		(808	)

Total net assets (liabilities)	$	194	$	(8	)	$	(800	)	$	(614	)	$	194	$	(8	)	$	(800	)	$	(614	)


Six Months Ended June 30, 2012	Mark-to-Market Derivatives
Three Months Ended September 30, 2012				Mark-to-Market Derivatives
Balance as of June 30, 2012				$	(617	)
Total realized / unrealized gains included in regulatory assets(a)(b)					195

Balance as of September 30, 2012				$	(422	)


Nine Months Ended September 30, 2012				Mark-to-Market Derivatives
Balance as of December 31, 2011	$	(800	)	$	(800	)
Total realized / unrealized gains included in regulatory assets(a)(b)		183			378

Balance as of June 30, 2012	$	(617	)
Balance as of September 30, 2012				$	(422	)


Six Months Ended June 30, 2011	Mark-to-Market Derivatives
Three Months Ended September 30, 2011				Mark-to-Market Derivatives
Balance as of June 30, 2011				$	(788	)
Total realized / unrealized gains included in regulatory assets(a)(b)					76

Balance as of September 30, 2011				$	(712	)


Nine Months Ended September 30, 2011				Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(971	)	$	(971	)
Total realized / unrealized gains included in regulatory assets(a)(b)		183			259

Balance as of June 30, 2011	$	(788	)
Balance as of September 30, 2011				$	(712	)

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 ~~June~~September 30, 2012 and December 31, 2011:


As of June 30, 2012	Level 1		Level 2			Level 3		Total
As of September 30, 2012											Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	184	$	—		$	—	$	184		$	528	$	—		$	—	$	528
Rabbi trust investments — mutual funds(b)(c)		8		—			—		8			9		—			—		9

Total assets		192		—			—		192			537		—			—		537

Liabilities
Deferred compensation obligation		—		(18	)		—		(18	)		—		(18	)		—		(18	)

Total liabilities		—		(18	)		—		(18	)		—		(18	)		—		(18	)

Total net assets (liabilities)	$	192	$	(18	)	$	—	$	174		$	537	$	(18	)	$	—	$	519


As of December 31, 2011	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	175	$	—		$	—	$	175		$	175	$	—		$	—	$	175
Rabbi trust investments — mutual funds(b)(c)		9		—			—		9			9		—			—		9

Total assets		184		—			—		184			184		—			—		184

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

Total liabilities		—		(21	)		—		(21	)		—		(21	)		—		(21	)

Total net assets (liabilities)	$	184	$	(21	)	$	—	$	163		$	184	$	(21	)	$	—	$	163

PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three and ~~six~~nine months ended ~~June~~September 30, 2012.

The following tables present assets and liabilities measured and recorded at fair value on BGE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~June~~September 30, 2012 and December 31, 2011:


As of June 30, 2012	Level 1		Level 2			Level 3		Total
As of September 30, 2012											Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	25	$	—		$	—	$	25		$	52	$	—		$	—	$	52
Rabbi trust investments — mutual funds		5		—			—		5			5		—			—		5

Total assets		30		—			—		30			57		—			—		57

Liabilities
Deferred compensation obligation		—		(5	)		—		(5	)		—		(5	)		—		(5	)

Total liabilities		—		(5	)		—		(5	)		—		(5	)		—		(5	)

Total net assets (liabilities)	$	30	$	(5	)	$	—	$	25		$	57	$	(5	)	$	—	$	52


As of December 31, 2011											Level 1		Level 2			Level 3		Total
Assets
Cash equivalents											$	33	$	—		$	—	$	33

Total assets												33		—			—		33

Liabilities
Total net assets (liabilities)											$	33	$	—		$	—	$	33

BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2012.

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, PECO and BGE). 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 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 limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. 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.

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 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.

Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual 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 equity 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. Commingled and mutual 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.

Direct lending funds are investments in managed funds which invest in private companies for long-term capital appreciation. The fair value of these securities is determined using either an enterprise value model or a bond valuation model. Investments in direct lending funds are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models.

Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). 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 investments are in fixed-income commingled funds and mutual funds, including short-term investment funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For fixed-income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Fixed-income commingled funds and mutual funds which are publicly quoted, such as money market funds, have been categorized as Level 1 given the clear observability of the prices.

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’ pricing is verified 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 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. Such instruments are categorized in Level 3.

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 determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs

are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 8 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). 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.

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)

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. 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 executive officer, chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Risk Oversight Committee of the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio are reviewed and verified by the middle office and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, 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 end of the reporting period in which 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 into Level 2 from Level 3 generally occur when the contract tenure becomes more observable.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The most significant position is the long term intercompany swap with ComEd, which is further discussed in Note 8 — Derivative Financial Instruments. The calculated fair value includes marketability discounts for margining provisions and notional size. Generation’s remaining Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, and transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by the traders and portfolio managers and verified by risk management considering published exchange transaction prices, executed bilateral transactions,

broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price is generally a product of the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly liquid and prices are observable for up to three years in the future. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is generally less than $4$4.00 and ~~$.25~~$0.25 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.

In 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 8 —– Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions

include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.

The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

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

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.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation will no longer utilize the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative

contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 of the Exelon 2011 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.

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 derivative congestion products, 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 that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of ~~June~~September 30, 2012, the percentage of expected generation hedged was ~~99%-102%~~98%-101%, ~~79%-82%~~87%-90%, 55%-58% and ~~46%-49%~~20%-23% for 2012, 2013, 2014 and ~~2014,~~2015, 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 excluding owned generation to be retired or sold in 2012. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including, sales to ComEd, PECO and BGE 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 process, which are further discussed in Note 2 of the Exelon 2011 Form 10-K, qualify for the NPNS 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.

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 volume is 3,000 MWs 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 was originally designated by Generation as a cash flow hedge. As discussed previously, effective with the date of merger with Constellation, Generation de-designated this swap as a cash flow hedge and began recording changes in fair value through current earnings as of that date. Generation records the fair value of the swap on its balance sheet and originally recorded changes in fair value to OCI. The value frozen in OCI as of the date of merger for this swap is reclassified into Generation’s earnings as the swap settles. ComEd has not elected hedge accounting for this derivative financial instrument. Since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and, therefore, the change in fair value each period is recorded as a regulatory asset or liability on ComEd’s Consolidated Balance Sheets. See Note 2 of the Exelon 2011 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.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Program, which is further discussed in Note 4 — 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 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 on PECO’s Consolidated Balance Sheet were amortized over the terms of the contracts, which ended on December 31, 2011.

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 asset management agreements that are derivatives either qualify for the normal purchases and normal sales scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the ~~2011~~2012 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 ~~2011~~2012 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% 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 with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of ~~4,248~~4,352 GWh and ~~6,077~~9,981 GWh for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and ~~1,496~~1,679 GWh and ~~2,829~~4,508 GWh for the three and ~~six~~nine months ended ~~June~~September 30, 2011, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.

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 manage interest rate risks. For interest rate 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 interest rate transaction occurs. For interest rate hedges that qualify and are designated as fair value hedges, only the ineffective portion of the derivative gain or loss will impact earnings. Assuming the fair value and cash flow hedges are effective, a hypothetical 50 bps increase in the interest rates associated with variable-rate debt and interest rate swaps would result in ~~less than a~~approximately $ 2 million decrease in ~~each of Exelon’s, Generation’s and PECO’s~~Exelon Consolidated pre-tax income for the ~~six~~nine months ended ~~June~~September 30, 2012. Below is a summary of the interest rate hedges as of ~~June~~September 30, 2012.


	Generation												Other			Exelon			Generation												Other		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges (a)			Proprietary Trading (a)			Subtotal			Derivatives Designated as Hedging Instruments			Total			Derivatives Designated as Hedging Instruments			Economic Hedges (a)			Proprietary Trading (a)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	—		$	4		$	16		$	20		$	—		$	20		$	—		$	3		$	19		$	22		$	—	$	22
Mark-to-market derivative assets (Noncurrent Assets)		42			9			36			87			14			101			42			10			37			89			14		103

Total mark-to-market derivative assets	$	42		$	13		$	52		$	107		$	14		$	121		$	42		$	13		$	56		$	111		$	14	$	125

Mark-to-market derivative liabilities (Current Liabilities)	$	(1	)	$	(1	)	$	(17	)	$	(19	)	$	—		$	(19	)	$	(1	)	$	(2	)	$	(19	)	$	(22	)	$	—	$	(22	)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(34	)		—			(36	)		(70	)		(1	)		(71	)		(36	)		—			(37	)		(73	)		—		(73	)

Total mark-to-market derivative liabilities	$	(35	)	$	(1	)	$	(53	)	$	(89	)	$	(1	)	$	(90	)	$	(37	)	$	(2	)	$	(56	)	$	(95	)	$	—	$	(95	)

Total mark-to-market derivative net assets (liabilities)	$	7		$	12		$	(1	)	$	18		$	13		$	31		$	5		$	11		$	—		$	16		$	14	$	30

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:


	Gain (Loss) on Swaps					Gain (Loss) on Borrowings					Gain (Loss) on Swaps					Gain (Loss) on Borrowings
	Six Months Ended June 30,					Six Months Ended June 30,					Nine Months Ended September 30,					Nine Months Ended September 30,
Income Statement Classification	2012			2011		2012			2011		2012			2011		2012			2011
Interest expense(a)	$	(2	)	$	—	$	(3	)	$	—	$	(3	)	$	1	$	(6	)	$	(1	)

At ~~June~~September 30, 2012 and December 31, 2011, Exelon had $650 million and $100 million, respectively, of notional amounts of fixed-to-floating fair value hedges outstanding related to interest rate swaps, with unrealized gain of $55 million and $14 million, respectively, which expire in 2015. Upon merger closing, $550 million of fixed-to-floating interest rate swaps previously at Constellation with a fair value of $44 million, as of March 12, 2012, were re-designated as fair value hedges. During the ~~six~~nine months ended ~~June~~September 30, 2012 and ~~June~~September 30, 2011, the impact of loss on the results of operations as a result of ineffectiveness from fair value hedges was ~~$1 million and $0 million, respectively.~~immaterial.

At ~~June~~September 30, 2012, Exelon had $150 million of notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with unrealized gain of $5 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the period from March 12 to ~~June~~September 30, 2012, the impact on the results of operations was immaterial.

Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley acquisition, as discussed in Note 9 — Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of April 5, 2014, by which date Generation anticipates that the DOE loan to be fully drawn. The swap hedges approximately 75% of Generation’s future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge will be recorded in other comprehensive income within Generation’s Consolidated Balance Sheets, with any ineffectiveness recorded in Generation’s Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, will be amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan.

As Generation draws down on the loan, a portion of the cash flow hedge will be de-designated and the related gains or losses will be reflected in earnings. In order to mitigate this earnings impact, a series of offsetting hedge transactions will be executed as Generation draws on the loan.

Antelope Valley received aits first loan advance on April 5, 2012, and several additional advances subsequently, as described in Note 9 — Debt and Credit Agreements. As of September 30, 2012, Generation has

entered into a series of fixed-to-floating interest rate ~~swap~~swaps with aan aggregated notional amount of ~~$52~~$119 million, 75% of the loan advance amount to offset ~~a portion~~portions of the original interest rate hedge, which isare de-designated as a cash flow hedge. The remaining cash flow hedge has a notional amount of ~~$433~~$365 million.

At ~~June~~September 30, 2012, Generation’s mark-to-market non-current derivative liability relating to the interest rate swap in connection with the loan agreement to fund Antelope Valley was ~~$31~~$32 million.

During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance a solar project. The swaps have a total notional amount of $31 million as of ~~June~~September 30, 2012 and expire in 2027. Upon the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At ~~June~~September 30, 2012, the subsidiary had a $4 million non-current derivative liability related to these swaps.

During the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

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 NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of ~~June~~September 30, 2012:


	Generation												ComEd			Other			Exelon			Generation												ComEd			Other			Exelon
Derivatives	Economic Hedges(a)			Proprietary Trading			Collateral and Netting(b)			Subtotal (c)			Economic Hedges (a)(d)			Intercompany Eliminations (a)			Total Derivatives			Economic Hedges(a)			Proprietary Trading			Collateral and Netting(b)			Subtotal (c)			Economic Hedges (a)(d)			Intercompany Eliminations (a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	4,863		$	5,360		$	(9,073	)	$	1,150		$	—		$	—		$	1,150		$	3,399		$	3,694		$	(6,187	)	$	906		$	—		$	—		$	906
Mark-to-market derivative assets with affiliate (current assets)		506			—			—			506			—			(506	)		—			352			—			—			352			—			(352	)		—
Mark-to-market derivative assets (noncurrent assets)		2,797			1,664			(3,321	)		1,140			—			—			1,140			2,133			1,147			(2,343	)		937			—			—			937
Mark-to-market derivative assets with affiliate (noncurrent assets)		—			—			—			—			—			—			—

Total mark-to-market derivative assets	$	8,166		$	7,024		$	(12,394	)	$	2,796		$	—		$	(506	)	$	2,290		$	5,884		$	4,841		$	(8,530	)	$	2,195		$	—		$	(352	)	$	1,843

Mark-to-market derivative liabilities (current liabilities)	$	(4,405	)	$	(5,360	)	$	8,974		$	(791	)	$	(19	)	$	—		$	(810	)	$	(2,951	)	$	(3,675	)	$	6,144		$	(482	)	$	(17	)	$	—		$	(499	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			(506	)		506			—			—			—			—			—			(352	)		352			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(1,903	)		(1,609	)		3,097			(415	)		(92	)		—			(507	)		(1,369	)		(1,106	)		2,193			(282	)		(53	)		—			(335	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			—			—

Total mark-to-market derivative liabilities	$	(6,308	)	$	(6,969	)	$	12,071		$	(1,206	)	$	(617	)	$	506		$	(1,317	)	$	(4,320	)	$	(4,781	)	$	8,337		$	(764	)	$	(422	)	$	352		$	(834	)

Total mark-to-market derivative net assets (liabilities)	$	1,858		$	55		$	(323	)	$	1,590		$	(617	)	$	—		$	973		$	1,564		$	60		$	(193	)	$	1,431		$	(422	)	$	—		$	1,009

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2011:

Cash Flow Hedges (Exelon and Generation). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. The net unrealized gains associated with the de-designated cash flow hedges prior to the merger was $1,928 million including $693 million related to the intercompany swap with ComEd. Approximately ~~$1,105~~$906 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 ~~$521~~$383 million related to the financial swap with ComEd. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2012 through 2014.

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 months ended ~~June~~September 30, 2012 and 2011, 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 ~~six~~nine months ended ~~June~~September 30, 2012, 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.


			Total Cash Flow Hedge OCI Activity, Net of Income Tax								Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon					Generation			Exelon
Three Months Ended June 30, 2012	Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2012			$	1,166	(a)(c)	$	703
Effective portion of changes in fair value				—	(e)		(17	)(d)
Three Months Ended September 30, 2012									Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30, 2012											$	923	(a)(c)	$	547
Reclassifications from accumulated OCI to net income		Operating Revenues		(243	)(b)		(139	)		Operating Revenues		(171	)(b)		(88	)(d)
Ineffective portion recognized in income		Operating Revenues		—			—			Operating Revenues		—			—
Accumulated OCI derivative gain at September 30,
2012											$	752	(a)(c)	$	459

Accumulated OCI derivative gain at June 30, 2012			$	923	(a)(c)	$	547


			Total Cash Flow Hedge OCI Activity, Net of Income Tax								Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon					Generation			Exelon
Six Months Ended June 30, 2012	Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Nine Months Ended September 30, 2012									Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2011			$	925	(a)(c)	$	488				$	925	(a)(c)	$	488
Effective portion of changes in fair value				432	(e)		300					432	(e)		301	(d)
Reclassifications from accumulated OCI to net income		Operating Revenues		(437	)(b)		(244	)		Operating Revenues		(608	)(b)		(332	)
Ineffective portion recognized in income		Operating Revenues		3			3			Operating Revenues		3			3

Accumulated OCI derivative gain at June 30, 2012			$	923	(a)(c)	$	547
Accumulated OCI derivative gain at September 30, 2012											$	752	(a)(c)	$	459


			Total Cash Flow Hedge OCI Activity, Net of Income Tax								Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon					Generation			Exelon
Three Months Ended June 30, 2011	Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2011			$	941	(a)	$	354
Three Months Ended September 30, 2011									Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at June 30, 2011											$	688	(a)(d)	$	209
Effective portion of changes in fair value				(106	)(b)		(64	)				(26	)(b)		(26	)
Reclassifications from accumulated OCI to net income		Operating Revenues		(143	)(c)		(77	)		Operating Revenues		(98	)(c)		(45	)
Ineffective portion recognized in income		Operating Revenues		(4	)		(4	)		Purchased Power		7			7

Accumulated OCI derivative gain at June 30, 2011			$	688	(a)(d)	$	209
Accumulated OCI derivative gain at September 30, 2011											$	571	(a)(d)	$	145

During the three and ~~six~~nine months ended ~~June~~September 30, 2012, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a ~~$402~~$283 million and a ~~$722~~$ 1,005 million pre-tax gain, respectively, and a ~~$237~~$162 million and ~~$454~~$617 million pre-tax gain for the three and ~~six~~nine months ended ~~June~~September 30, 2011. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges was primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference was 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 $5 million for the ~~six~~nine months ended ~~June~~September 30, 2012. There was no ineffectiveness for the three months ended ~~June~~September 30, 2012 as Generation will not incur changes in cash flow hedge ineffectiveness in future periods as all commodity cash flow hedge positions were de-designated prior to the merger date.

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 ~~$230~~$145 million and ~~$403~~$548 million pre-tax gain for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and a ~~$127~~$74 million and ~~$231~~$305 million pre-tax gain for the three and ~~six~~nine months ended 2011, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices were $5 million for the ~~six~~nine months ended ~~June~~September 30, 2012. There was no ineffectiveness for the three months ended ~~June~~September 30, 2012 as Generation will not incur changes in cash flow hedge ineffectiveness in future periods as all commodity cash flow hedge positions were de-designated prior to the merger date.

Economic Hedges (Exelon and Generation). These instruments represent hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and physical forward sales and purchases. For the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel 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 3^rd quarter of 2012, Generation completed a non-cash exchange by issuing a new in-the-money derivative with a new counterparty in exchange for novating to them existing in-the-money trades with the old counterparty for a total of $51 million. This transaction did not have any Income Statement effect to Generation. 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.


	Generation									Intercompany Eliminations			Exelon		Generation									Intercompany Eliminations			Exelon
Three Months Ended June 30, 2012	Operating Revenues			Purchased Power and Fuel			Total			Operating Revenues(a)			Total
Three Months Ended September 30, 2012															Operating Revenues			Purchased Power and Fuel			Total			Operating Revenues(a)			Total
Change in fair value	$	44		$	12		$	56		$	16		$	72	$	(255	)	$	129		$	(126	)	$	35		$	(91	)
Reclassification to realized at settlement		(54	)		198			144			(10	)		134		20			122			142			(19	)		123

Net mark-to-market gains (losses)	$	(10	)	$	210		$	200		$	6		$	206	$	(235	)	$	251		$	16		$	16		$	32


	Generation									Intercompany Eliminations			Exelon		Generation									Intercompany Eliminations			Exelon
Six Months Ended June 30, 2012	Operating Revenues			Purchased Power and Fuel			Total			Operating Revenues(a)			Total
Nine Months Ended September 30, 2012															Operating Revenues			Purchased Power and Fuel			Total			Operating Revenues(a)			Total
Change in fair value	$	177		$	(28	)	$	149		$	27		$	176	$	(85	)	$	121		$	36		$	62		$	98
Reclassification to realized at settlement		(109	)		225			116			(10	)		106		(81	)		326			245			(29	)		216

Net mark-to-market gains	$	68		$	197		$	265		$	17		$	282
Net mark-to-market gains (losses)															$	(166	)	$	447		$	281		$	33		$	314


	Exelon and Generation														Exelon and Generation
Three Months Ended June 30, 2011 (As Reported)	Operating Revenues			Purchased Power and Fuel			Total
Three Months Ended September 30, 2011 (As Reported)															Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	—		$	(4	)	$	(4	)						$	—		$	22		$	22
Reclassification to realized at settlement		—			(126	)		(126	)							—			(101	)		(101	)

Net mark-to-market (losses)(b)	$	—		$	(130	)	$	(130	)						$	—		$	(79	)	$	(79	)


	Exelon and Generation														Exelon and Generation
Six Months Ended June 30, 2011 (As Reported)	Operating Revenues			Purchased Power and Fuel			Total
Nine Months Ended September 30, 2011 (As Reported)															Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	—		$	(7	)	$	(7	)						$	—		$	13		$	13
Reclassification to realized at settlement		—			(273	)		(273	)							—			(372	)		(372	)

Net mark-to-market (losses)(b)	$	—		$	(280	)	$	(280	)						$	—		$	(359	)	$	(359	)


	Exelon and Generation
Three Months Ended June 30, 2011 (Pro Forma)	Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	12		$	(16	)	$	(4	)
Reclassification to realized at settlement		(137	)		11			(126	)

Net mark-to-market (losses)(b)	$	(125	)	$	(5	)	$	(130	)


	Exelon and Generation									Exelon and Generation
Six Months Ended June 30, 2011 (Pro Forma)	Operating Revenues			Purchased Power and Fuel			Total
Three Months Ended September 30, 2011 (Pro Forma)										Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	13		$	(20	)	$	(7	)	$	31		$	(9	)	$	22
Reclassification to realized at settlement		(271	)		(2	)		(273	)		(105	)		4			(101	)

Net mark-to-market (losses)(b)	$	(258	)	$	(22	)	$	(280	)	$	(74	)	$	(5	)	$	(79	)


										Exelon and Generation
Nine Months Ended September 30, 2011 (Pro Forma)										Operating Revenues			Purchased Power and Fuel			Total
Change in fair value										$	44		$	(31	)	$	13
Reclassification to realized at settlement											(374	)		2			(372	)

Net mark-to-market (losses)(b)										$	(330	)	$	(29	)	$	(359	)

Proprietary Trading Activities (Exelon and Generation). For the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, 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 June 30,					Six Months Ended June 30,					Location on Income Statement		Three Months Ended September 30,						Nine Months Ended September 30,
	Location on Income Statement		2012		2011			2012		2011			Location on Income Statement		2012			2011			2012		2011
Change in fair value		Operating Revenue	$	12	$	16		$	14	$	19			Operating Revenue	$	(2	)	$	2		$	12	$	22
Reclassification to realized at settlement		Operating Revenue		31		(7	)		32		(12	)		Operating Revenue		25			(6	)		57		(19	)

Net mark-to-market gains		Operating Revenue	$	43	$	9		$	46	$	7			Operating Revenue	$	23		$	(4	)	$	69	$	3

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.

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of ~~June~~September 30, 2012. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX, ICE and Nodal 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, PECO and BGE of ~~$61~~$53 million, ~~$59~~$53 million and $11 million, respectively.


Rating as of June 30, 2012	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
Rating as of September 30, 2012											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	$	2,523	$	802	$	1,721		—	$	—	$	1,968	$	492	$	1,476		—	$	—
Non-investment grade		88		41		47		—		—		46		25		21		—		—
No external ratings
Internally rated — investment grade		552		16		536		1		286		501		16		485		1		267
Internally rated — non-investment grade		64		7		57		—		—		90		2		88		—		—

Total	$	3,227	$	866	$	2,361		1	$	286	$	2,605	$	535	$	2,070		1	$	267


Net Credit Exposure by Type of Counterparty	As of June 30, 2012		As of September 30, 2012
Investor-owned utilities, marketers and power producers	$	1,091	$	902
Energy cooperatives and municipalities		775		710
Financial institutions		406		386
Other		89		72

Total	$	2,361	$	2,070

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of ~~June~~September 30, 2012, 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 Exelon 2011 Form 10-K for further information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements

with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies 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 ~~June~~September 30, 2012, PECO had no net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply 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 4 —- 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; however, the natural gas asset managers have provided $14 million in parental guarantees related to these agreements. As of ~~June~~September 30, 2012, PECO had credit exposure of $4$8 million under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 6 of BGE’s 2011 Form 10-K for further information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. 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. The seller’s credit exposure is calculated each business day. As of ~~June~~September 30, 2012, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demand, which are not covered by the gas cost adjustment clause. At ~~June~~September 30, 2012, BGE had credit exposure of $2$1 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third party suppliers.

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

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. Generation also enters into commodity transactions on NYMEX, ICE, and Nodal Exchanges (“the exchanges”). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and

margining requirements. 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. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

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 the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk Related Contingent Feature	Credit-Risk Related Contingent Feature		June 30, 2012	Credit-Risk Related Contingent Feature		September 30, 2012
Gross Fair Value of Derivative Contracts Containing this Feature(a)		Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b)	Net Fair Value of Derivative Contracts Containing This Feature(c)		Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b)	Net Fair Value of Derivative Contracts Containing This Feature(c)
($4,126)		$3,235	($891)
($2,720)					$2,156	($564)

Credit-Risk Related Contingent Feature	Credit-Risk Related Contingent Feature		December 31, 2011	Credit-Risk Related Contingent Feature		December 31, 2011
Gross Fair Value of Derivative Contracts Containing this Feature(a)		Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b)	Net Fair Value of Derivative Contracts Containing This Feature(c)		Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements(b)	Net Fair Value of Derivative Contracts Containing This Feature(c)
($1,014)		$928	($86)		$928	($86)

Generation has cash collateral posted of ~~$697~~$415 million and letters of credit posted of ~~$1,189~~$973 million and cash collateral held of ~~$1,007~~$607 million and letters of credit held of ~~$152~~$109 million as of ~~June~~September 30, 2012 and cash collateral held of $542 million and letters of credit held of $89 million at December 31, 2011. In the event of a credit downgrade below investment grade (i.e. BB+ or Ba1), Exelon Generation Company, LLC and Constellation Energy Commodities Group, Inc. could be required to post additional collateral of ~~$2,375~~$2,004 million as of ~~June~~September 30, 2012 and $1,612 million as of December 31, 2011. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of ~~June~~September 30, 2012, Generation’s swaps were in an asset position, with a fair value of ~~$18~~$16 million.

See Note 18 of the Exelon 2011 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into SFCs with certain utilities, including PECO and BGE, with one-sided collateral postings only from 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 the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the 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 contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of ~~June~~September 30, 2012, ComEd held ~~both~~neither cash ~~and~~nor letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. ~~These amounts were not material.~~ Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of ~~June~~September 30, 2012, ComEd held approximately ~~$20~~$19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 2 of the Exelon 2011 Form 10-K for further information.

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 the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of ~~June~~September 30, 2012, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of ~~June~~September 30, 2012, PECO could have been required to post approximately ~~$36~~$30 million of collateral to its counterparties.

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.

BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of ~~June~~September 30, 2012, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of ~~June~~September 30, 2012, BGE could have been required to post approximately ~~$54~~$51 million of collateral to its counterparties.

Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Exelon’s debt ratings were to materially weaken, 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 less charges.

~~(Dollars~~ As of September 30, 2012, Exelon’s swaps were in ~~millions, except per share data, unless otherwise noted)~~

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

As of ~~June~~September 30, 2012 and December 31, 2011, ~~$13~~$1 million of cash collateral posted and $2 million ~~respectively,~~ of cash collateral received was not offset against derivative positions because they were not associated with energy-related derivatives.

The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2012 and December 31, 2011:

Exelon had bank lines of credit under committed credit facilities at ~~June~~September 30, 2012 for short-term financial needs, as follows:

Type of Credit Facility

Amount(a)

Expiration Dates

Capacity Type

Amount(a)

Expiration Dates

Capacity Type

(In billions)

Exelon Corporate

Syndicated Revolver

2.00

October 2013 to March 2016

Letters of credit and cash

Bilateral

0.90

September 2013 to December 2014

Letters of credit and cash

Syndicated Revolvers

2.0

December 2012 and August 2017

Letters of credit and cash

Generation

Syndicated Revolver

5.30

March 2016

Letters of credit and cash

5.3

August 2017

Letters of credit and cash

Bilateral

0.30

December 2015 and March 2016

Letters of credit and cash

0.3

December 2015 and March 2016

Letters of credit and cash

ComEd

Syndicated Revolver

1.00

March 2017

Letters of credit and cash

1.0

March 2017

Letters of credit and cash

PECO

Syndicated Revolver

0.60

March 2016

Letters of credit and cash

0.6

August 2017

Letters of credit and cash

BGE

Syndicated Revolver

0.60

March 2015

Letters of credit and cash

0.6

August 2017

Letters of credit and cash

Total

10.70

9.8

As of ~~June~~September 30, 2012, there were no borrowings under the Registrants’ credit facilities.

~~The Registrants had the following amounts of commercial paper borrowings outstanding as of June 30, 2012 and December 31, 2011:~~

and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. ComEd incurred $3 million in costs related to the replacement of the credit facility. These costs included upfront arranger fees and filing costs, which will be amortized to interest expense over the term of the credit facility.

Borrowings under the credit agreement may bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon ComEd’s credit rating. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreement requires ComEd to pay a facility fee based upon the aggregate commitments under the agreement. The maximum facility fee is 35 basis points. The fee varies depending upon ComEd’s credit rating. As of June 30, 2012, ComEd adders were 27.5 basis points and 127.5 basis points for prime rate and LIBOR-based rate borrowings, respectively.

In connection with the Upstream Merger, Exelon assumed all of Constellation’s obligations under its three-year, unsecured revolving credit facility (the “Constellation Credit Agreement”). Effective as of the Initial Merger, the Constellation Credit Agreement was amended and restated to (1) permit Exelon and Constellation to consummate the Upstream Merger and the restructuring transaction, (2) reduce the aggregate commitments under the Constellation Credit Agreement from $2.5 billion to $1.5 billion, and (3) conform some of the representations, warranties, covenants and events of default in the Constellation Credit Agreement with representations, warranties, covenants and events of default in the Exelon credit agreement, dated as of March 23, 2011, as amended as of the Initial Merger. In connection with the Upstream Merger, Exelon also assumed Constellation’s obligations under four separate bilateral credit facilities and a commodity-linked credit facility, which were also amended to conform with the Constellation Credit Agreement effective as of the Initial Merger. Effective as of the Initial Merger, the Exelon Credit Agreement and the Generation Credit Agreement were amended and restated to conform some of the representations, warranties and covenants with provisions of the Constellation Credit Agreement, as amended effective as of the Initial Merger. Exelon Corporation (as successor to Constellation Energy Group) entered into an amendment to the Amended and Restated Credit Agreement dated March 12, 2012, which changed the maturity date to December 31, 2012. See Note 3 — Merger and Acquisitions for further description of the merger transaction.

On ~~July 18,~~March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new unsecured facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement has an initial term expiring on March 28, 2017, and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to amend and extend the facilities for ComEd were not material.

Borrowings under the credit agreement may bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon ComEd’s credit rating. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The fee varies depending upon ComEd’s credit rating. The credit agreement also requires ComEd to pay a facility fee based upon the aggregate commitments under the agreement.

On August 10, 2012, Exelon Corporate, Generation, PECO and BGE ~~began the process of amending~~amended and ~~extending~~extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, through August 10, 2017. Under these facilities Exelon Corporate, Generation, PECO and BGE may issue letters of credit in the aggregate of up to $200 million, $3.5 billion, $300 million and $600 million, respectively. Each credit facility permits the applicable borrower to request extensions for up to two additional one-year periods. Each credit facility also allows Exelon Corporate, Generation, PECO and BGE to request increases in aggregate commitments up to an additional $250 million, $1.0 billion, $250 million and $100 million, respectively. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material.

The amended credit facilities ~~will~~updated the credit ratings-based pricing grids used to determine the facility fee and interest rates for borrowings under each facility and reflect current market pricing and maturities of five years from the close of the transactions. Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon the prime rate or upon a LIBOR-based rate. Exelon Corporate, Generation, PECO and BGE have adders of 27.5, 7.5, 0.0 and 7.5 basis points for prime based borrowings and 127.5, 107.5, 100.0 and 107.5 basis points for LIBOR-based borrowings. The ~~transactions~~fee varies depending upon the respective credit ratings of each entity. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are ~~expected to close~~65 basis points and ~~become effective~~165 basis points, respectively. The covenants in ~~August 2012. The new covenants~~each of Exelon Corporate, Generation, PECO and BGE’s extended facilities are ~~expected to be~~ substantially consistent with existing ~~covenants. Generally, it is expected that costs incurred to amend and extend~~covenants, with the ~~facilities will be amortized over the newly extended lives~~exception of the ~~facilities. The maturity~~BGE facility, in which a debt to capitalization financial covenant was replaced with an interest coverage ratio financial covenant.

On October 19, 2012, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new minority and community bank credit facility agreements in the amounts of $50 million, $34 million and $34 million, respectively, and BGE entered into a minority and community bank credit facility in the ~~$1.5 billion Constellation Credit Agreement will be amended~~amount of $5 million. These facilities, which expire in October 2013, are solely utilized to ~~December 31, 2012.~~issue letters of credit.

On June 18, 2012, Generation issued and sold $775 million of Senior Notes. In connection with this debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $470 million. The interest rate swaps were settled on June 15, 2012 with Generation recording a pre-tax loss of approximately $7 million. The loss was recorded to other comprehensive income within Exelon’s and Generation’s Consolidated Balance Sheets and ~~will be~~are being amortized to income over the life of the related debt as an increase to interest expense.

Concurrently with the new debt issuance, Generation engaged in private offers (the Exchange Offer) to certain eligible holders to exchange any and all of the $700 million outstanding 7.60% Senior Notes due 2032 (Old Notes) of Exelon (which were assumed by Exelon in the merger with Constellation), for:

On June 28, 2012, pursuant to the Exchange Offer, Generation purchased $441 million of the Old Notes in exchange for issuing $535 million of Notes due in 2022 and 2042, plus a cash payment of approximately $60 million. The $441 million of Old Notes were recorded on Exelon’s Consolidated Balance Sheets at $608 million, reflecting a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger which resulted in approximately $13 million gain from the Exchange Offer at Generation. The gain was recorded as an increase to Long-term Debt within Exelon’s and Generation’s Consolidated Balance Sheets and will be amortized to income over the life of the debt as a reduction in interest expense.

On July 13, 2012, pursuant to the Exchange Offer described above, Generation purchased an additional $1 million of Old Notes in exchange for the Senior Notes due in 2022 and 2042.

In connection with the debt obligations assumed by Exelon as part of the Upstream Merger on March 12, 2012, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt on Generation’s Consolidated Balance Sheets and

intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. The third-party debt obligations are reported in Long-term Debt on Exelon’s Consolidated Balance Sheets. The intercompany loan agreements are summarized as follows:

The intercompany loan agreements and the third-party debt obligations described above were increased by $403 million for a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger, of which ~~$224~~$212 million was outstanding as of ~~June~~September 30, 2012, primarily reflecting the Exchange Offer described above. This premium is being amortized over the lives of the arrangements as a reduction to interest expense.

Generation filed a registration statement on Form S-4 on November 1, 2012 to register senior notes to be issued in connection with an exchange offer for the senior notes that were privately issued in June and July 2012. The registered notes will have the same terms and maturity dates as the privately placed senior notes.

During the nine months ended September 30, 2012, the following long-term debt was issued:

~~Issuance~~On October 1, 2012, ComEd issued $350 million aggregate principal of ~~Long-Term Debt~~its First Mortgage 3.80% Bonds, Series 113 due October 1, 2042. ComEd will use the net proceeds from the sale of the bonds to repay outstanding commercial paper obligations and for general corporate purposes.

During October 2012, Antelope Valley received DOE-guaranteed loan advances of $59 million at 2.482% and $2 million at 2.595%, due January 5, 2037.

During the ~~six~~nine months ended ~~June 30, 2012, the following long-term debt was issued:~~

~~During the six months ended June~~September 30, 2011, the following long-term debt was issued:

Company

Type

Interest
Rate

Maturity

Amount

Use of Proceeds

Type

Interest
Rate

Maturity

Amount

Use of Proceeds

ComEd

First Mortgage Bonds

1.625

January 15, 2014

600

Used as an interim source of liquidity for January 2011 contribution for Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes.

First Mortgage Bonds

1.625

January 15, 2014

600

Used as an interim source of
liquidity for January 2011
contribution for Exelon-sponsored
pension plans in which ComEd
participates and for other general
corporate purposes.

ComEd

First Mortgage Bonds(a)

1.950

September 1, 2016

250

To be used to refinance the
outstanding principal amount of
three series of variable rate tax-
exempt bonds, to refinance the
outstanding principal of First
Mortgage 5.40% Bonds due
December 15, 2011.

ComEd

First Mortgage Bonds(a)

3.400

September 1, 2021

350

During the ~~six~~nine months ended ~~June~~September 30, 2012, the following current and long-term debt was retired:

~~During the six months ended June 30, 2011, the following long-term debt was retired:~~


Company	Type	Interest Rate			Maturity		Amount		Type	Interest Rate			Maturity		Amount
ComEd									First Mortgage Bond Series 98		6.15	%		March 15, 2012	$	450
BGE									Rate Stabilization Bonds		5.68	%		April 1, 2017	$	31
BGE									Medium Term Notes		6.73 - 6.75	%		June 15, 2012	$	110
Generation	Kennett Square Capital Lease		7.83	%		September 20, 2020	$	1	Armstrong Co. tax-exempt		5.00	%		December 1, 2042	$	46
ComEd	Sinking fund debentures		4.75	%		December 1, 2011		1
Generation									CEU Credit Agreement		2.27	%		June 16, 2016	$	3
Generation									MEDCO Tax-Exempt Bonds		Variable			April 1, 2024	$	75
Generation									Solar Revolver		2.49	%		July 7, 2014	$	13
Generation									Kennett Square Capital Lease		7.83	%		September 20, 2020	$	2
Exelon									Senior Notes		7.60	%		April 1, 2032	$	442
Exelon									Medium Term Notes		7.30	%		June 1, 2012	$	2

On October 1, 2012, PECO retired $225 million aggregate principal of its 4.750% First and Refunding Mortgage Bonds due October 1, 2012.

On October 1, 2012, BGE retired $32 million aggregate principal of its 5.680% Rate Stabilization Bonds due April 1, 2017.

During the nine months ended September 30, 2011, the following long-term debt was retired:

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 is classified as a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. As of ~~June~~September 30, 2012 and December 31, 2011, the financial institution’s undivided interest in Exelon’s and PECO’s gross ~~customer~~ accounts receivable was equivalent to ~~$296~~$314 million and $329 million, respectively, which represents the financial institution’s interest in PECO’s eligible receivables as calculated under the terms of the agreement. The agreement requires PECO to maintain eligible receivables at least equivalent to the financial institution’s undivided interest. Effective April 30, 2012, PECO and the financial institution entered into an amendment to the agreement, which modified certain eligibility criteria that increased the amount of PECO’s receivables that will be considered eligible receivables under the agreement for purposes of satisfying this requirement. Upon termination or liquidation of this agreement, the financial institution is entitled to recover up to $225 million plus the accrued yield payable from its undivided interest in PECO’s receivables. On ~~September 2, 2011,~~August 31, 2012, PECO ~~extended~~entered into an Amendment to extend this agreement until August ~~31, 2012, unless extended in accordance with its terms.~~30, 2013. This Amendment also expands the criteria for eligible receivables to include receivables that have been purchased by PECO and revises the compliance criteria for the eligible asset test to allow for the payment of capital within a specified period of time. As of ~~June~~September 30, 2012, 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 may seek alternate financing.

On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million at an interest rate spread of 37.5 basis points above U.S. Treasury and maturity of January 5, 2037. The loan advance terminated the put option that Generation had on the Antelope Valley project. ~~As a result, Generation entered into a fixed-to-floating interest rate swap with a notional amount~~Antelope Valley received additional advances subsequent to the initial advance, and as of ~~$52~~September 30, 2012, has received $100 million ~~75% of the first loan advance amount to offset a portion of the original interest rate hedge.~~in DOE-guaranteed funding. See Note 8 — Derivative Financial Instruments for additional information on the interest rate ~~swap.~~swap related to the loan advances and Note 3 — Mergers and Acquisitions for additional information on the transaction.

In addition, Generation has issued letters of credit to support its equity investment in the project. As of ~~June~~September 30, 2012, Generation had ~~$669~~$656 million in letters of credit outstanding related to the project The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made.

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 June 30, 2012	Exelon(a)			Generation(a)			ComEd			PECO			BGE(b)
For the Three Months Ended September 30, 2012																Exelon(a)			Generation(a)			ComEd			PECO			BGE(b)
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		—	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.5			2.3			5.2			3.1			6.2			5.6			5.9			5.0			3.0			—
Qualified nuclear decommissioning trust fund income		(2.0	)		(3.8	)		—			—			—			7.8			21.5			—			—			—
Domestic production activities deduction		0.7			1.6			—			—			—			0.3			0.8			—			—			—
Tax exempt income		(0.4	)		(0.8	)		—			—			—			(0.2	)		(0.5	)		—			—			—
Health Care Reform Legislation		0.3			—			1.0			—			2.7			—			—			0.6			—			—
Amortization of investment tax credit		(0.7	)		(0.7	)		(0.8	)		(0.3	)		(1.7	)
Amortization of investment tax credit, net deferred taxes																	(4.8	)		(13.0	)		(0.5	)		(0.3	)		—
Plant basis differences		(0.7	)		—			0.1			(3.6	)		(4.7	)		(4.7	)		—			(0.5	)		(21.0	)		—
Production tax credits		(2.2	)		(4.0	)		—			—			—			(2.5	)		(7.4	)		—			—			—
Merger Expenses(c)		(0.8	)		—			—			—			—
Fines & penalties																	(0.1	)		—			—			—			—
Other(d)		(2.3	)		(3.6	)		0.3			0.2			(1.5	)		(1.2	)		7.1			—			0.2			—

Effective income tax rate		30.4	%		26.0	%		40.8	%		34.4	%		36.0	%		35.2	%		49.4	%		39.6	%		16.9	%		—	%


For the Nine Months Ended September 30, 2012																Exelon(a)			Generation(a)			ComEd			PECO			BGE(b)
U.S. Federal statutory rate																	35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit																	(4.7	)		2.5			5.4			3.2			2.3
Qualified nuclear decommissioning trust fund income																	6.9			10.9			—			—			—
Tax exempt income																	(0.3	)		(0.5	)		—			—			—
Health Care Reform Legislation																	0.2			—			0.6			—			(4.6	)
Amortization of investment tax credit, net deferred taxes																	(2.3	)		(3.3	)		(0.5	)		(0.3	)		2.9
Plant basis differences																	(2.2	)		—			(0.2	)		(9.7	)		7.2
Production tax credits																	(2.6	)		(4.3	)		—			—			—
Fines & penalties																	3.8			6.0			—			—			—
Merger expenses(c)																	3.6			—			—			—			(14.0	)
Other																	(1.3	)		0.8			0.2			(0.0	)		4.5

Effective income tax rate																	36.1	%		47.1	%		40.5	%		28.2	%		33.3	%


For the Six Months Ended June 30, 2012	Exelon(a)			Generation(a)			ComEd			PECO			BGE(b)
For the Nine Months Ended September 30, 2011																Exelon			Generation			ComEd			PECO			BGE(b)
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		(10.7	)		1.6			5.7			3.3			2.3			4.1			4.9			3.4			(0.4	)		4.8
Qualified nuclear decommissioning trust fund income		6.3			8.0			—			—			—			(0.6	)		(0.8	)		—			—			—
Domestic production activities deduction		(0.2	)		(0.2	)		—			—			—			(0.4	)		(0.6	)		—			—			—
Tax exempt income		(0.4	)		(0.5	)		—			—			—			(0.1	)		(0.2	)		—			—			—
Health Care Reform Legislation		0.2			—			0.6			—			(3.1	)		—			—			(1.5	)		—			(0.8	)
Amortization of investment tax credit		(0.7	)		(0.6	)		(0.5	)		(0.3	)		3.8			(0.3	)		(0.2	)		(0.4	)		(0.3	)		(0.5	)
Plant basis differences		(0.6	)		—			—			(3.6	)		10.6			(1.0	)		—			(0.4	)		(6.8	)		(1.6	)
Production tax credits		(2.6	)		(3.4	)		—			—			—			(1.0	)		(1.4	)		—			—			—
Fines & Penalties		6.1			7.6			—			—			—
Merger Expenses(c)		5.6			—			—			—			(18.3	)
Interest and penalties on unrecognized tax benefits(e)																	—			—			—			—			(1.1	)
Other		(1.3	)		(1.0	)		0.3			—			3.0			(0.3	)		(0.9	)		0.3			—			(0.1	)

Effective income tax rate		36.7	%		46.5	%		41.1	%		34.4	%		33.3	%		35.4	%		35.8	%		36.4	%		27.5	%		35.7	%


For the Three Months Ended June 30, 2011	Exelon			Generation			ComEd			PECO			BGE(b)
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		2.0			3.0			3.2			1.5			5.2
Qualified nuclear decommissioning trust fund income		1.3			1.9			—			—			—
Domestic production activities deduction		(1.0	)		(1.5	)		—			—			—
Tax exempt income		(0.2	)		(0.2	)		—			—			—
Health Care Reform Legislation		—			—			(4.8	)		—			2.8
Amortization of investment tax credit		(0.2	)		(0.2	)		(0.4	)		(0.3	)		(0.9	)
Plant basis differences		—			—			0.2			(0.1	)		(2.2	)
Production tax credits		(0.9	)		(1.5	)		—			—			—
Other		(1.1	)		(1.8	)		0.5			0.1			3.0

Effective income tax rate		34.9	%		34.7	%		33.7	%		36.2	%		42.9	%


For the Six Months Ended June 30, 2011	Exelon			Generation			ComEd			PECO			BGE(b)
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.9			4.7			4.9			(1.6	)		4.7
Qualified nuclear decommissioning trust fund income		1.8			2.6			—			—			—
Domestic production activities deduction		(1.0	)		(1.4	)		—			—			—
Tax exempt income		(0.1	)		(0.2	)		—			—			—
Health Care Reform Legislation		—			—			(2.8	)		—			(1.0	)
Amortization of investment tax credit		(0.2	)		(0.2	)		(0.4	)		(0.3	)		(0.3	)
Plant basis differences		—			—			(0.1	)		(0.2	)		(1.0	)
Production tax credits		(0.9	)		(1.3	)		—			—			—
Other		(0.8	)		(1.4	)		0.3			(0.2	)		—

Effective income tax rate		37.7	%		37.8	%		36.9	%		32.7	%		37.4	%

Exelon, Generation, ComEd, PECO, and BGE have ~~$1,050~~$980 million, ~~$885~~$829 million, $68 million, ~~$48~~$44 million, and ~~$10~~$0 million, respectively, of unrecognized tax benefits as of ~~June~~September 30, 2012. Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s uncertain tax positions have not significantly changed since December 31, 2011. See Note 11 of the Exelon 2011 Form 10-K and Note 10 of the 2011 Form 10-K for Constellation and BGE for further discussion of reasonably possible changes that could occur in unrecognized tax benefits during the next twelve months.

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. 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. 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.

Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represented compensation for a taking of their respective properties and, accordingly, were 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.

Status of Tax Positions. 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 includes IRS Appeals’ agreement to withdraw its assertion of the $110 million substantial understatement penalty with respect to Exelon’s involuntary conversion position. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits associated with the settled positions and established a current tax payable to the IRS. InExelon has received verbal confirmation from the ~~second quarter of 2012,~~ IRS ~~Appeals submitted the final terms, calculations, and definitive agreements to~~that the Joint Committee on Taxation ~~for its review.~~has approved the terms of the preliminary agreement and Exelon expects final IRS approval in the fourth quarter of 2012.

Under the terms of the agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2012 for the years for which there is a resulting tax deficiency, of which $405 million is attributable to ComEd, ($135) million to PECO, $10 million to Generation and the remainder to 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. In order to stop additional interest from accruing on the expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million.

Exelon and IRS Appeals to date have failed to reach a settlement with respect to the like-kind exchange position. The IRS has 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. 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. IRS Appeals also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange 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 2013. 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. Further, Exelon believes it is unlikely that the penalty assertion will ultimately be sustained. Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty, it would result in an after-tax charge of $86 million to Exelon’s and ComEd’s results of operations.

As of ~~June~~September 30, 2012, assuming Exelon’s settlement of the involuntary conversion position is finalized, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully

successful IRS challenge to Exelon’s like-kind exchange position could be as much as ~~$860~~$870 million, of which $510 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 ~~June~~September 30, 2012, by as much as $260 million, net of tax, of which $160 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.

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, such as the merger with Constellation. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they have state income tax obligations, which include Illinois, Maryland and Pennsylvania, as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the first quarter of 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the first quarter of 2012.

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The change to the newly adopted method for the 2011 tax year and through Q3 2012 resulted in a tax benefit of $19 million at Exelon, of which $22 million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic production activities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. Exelon currently anticipates that the IRS will issue guidance ~~during 2012~~in the near future providing a safe harbor method of tax accounting for gas transmission and distribution property to determine the tax treatment of repair costs for gas distribution assets. If PECO and BGE choose to change to a new gas distribution repair methodology, management anticipates it would likely result in an earnings and cash tax benefit at PECO. The effect at BGE is expected to be immaterial.

PECO’s approved 2010 natural gas distribution rate case settlement stipulates that the expected cash benefit resulting from the application of the new methodology to prior tax years must be refunded to customers over a seven-year period. The prospective tax benefit claimed as a result of the new methodology should be reflected in tax expense in the year in which it is claimed on the tax return and will be reflected in the determination of revenue requirements in the next natural gas distribution base rate case. See Note 2 of the Exelon 2011 Form 10-K for further information on the impact of the guidance on natural gas distribution base rate cases.property.

For the three and ~~six~~nine months ended ~~June~~September 30, 2012, BGE recorded an adjustment to interest expense of approximately $1$2 million and $7$9 million, respectively, to reflect the impacts of anticipated amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded this adjustment is not material to its results of operations or cash flows for the three and ~~six~~nine months ended ~~June~~September 30, 2012, or any prior period.

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. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2011 to ~~June~~September 30, 2012:


Nuclear decommissioning ARO at December 31, 2011(a)	$	3,680		$	3,680
Accretion expense		111			169
Net increase due to changes in estimated cash flows		80			749
Costs incurred to decommission retired plants		(1	)		(2	)

Nuclear decommissioning ARO at June 30, 2012(a)	$	3,870
Nuclear decommissioning ARO at September 30, 2012(a)				$	4,596

During the ~~six~~nine months ended ~~June~~September 30, 2012, Generation’s ARO increased by ~~$190 million, primarily due to increases for accretion and a net~~$916 million. The increase ~~of $80 million due to~~in the ARO is largely driven by four factors: i) changes in ~~estimated~~the timing of the future nominal cash flows ~~primarily related to increased costs~~ resulting from an ~~updated decommissioning cost study received for~~assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which have dramatically decreased given the current low interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities ~~generating station.~~and Dresden nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in estimated cash flows ~~had no impact to~~resulted in $10 million of expense, which is included in Exelon’s orand Generation’s Consolidated Statements of Operations and Comprehensive Income.

During the third quarter of 2011, Generation recorded a net increase in the ARO of $176 million primarily due to an increase in the estimated costs to decommission the Oyster Creek and Zion nuclear units resulting from the completion of updated decommissioning cost studies received in 2011 and an increase in the expected long-term escalation rates for energy, partially offset by decreases in long-term escalation rates for labor and other costs as compared to prior study periods. The increase in the Zion nuclear unit ARO resulted in $28 million of expense, which is included in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income, as the Zion nuclear unit is retired, and as such, is unable to record increases to the ARO through an ARC. Additionally, the Zion nuclear unit is not subject to a regulatory agreement that would provide for offset of the expense.

NDT funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO currently collects funds, in revenues, for decommissioning the former

PECO nuclear plants through regulated rates, and these collections may continue through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 30, 2012, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC

proposing an annual recovery from customers of $24 million, which reflects a reduction from the current approved annual collections of $29 million. On July 23, 2012, the PAPUC approved the filing and the new rates will be effective January 1, 2013. See Note 12 of the Exelon 2011 Form 10-K for information regarding amounts collected from PECO customers for decommissioning costs. See below for discussion of NRC minimum funding requirements.

In the first half of 2012, the NDT fixed income portfolio completed the transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and short-term corporate lending. There was no change in the equity investment strategy.

At ~~June~~September 30, 2012 and December 31, 2011, Exelon and Generation had NDT fund investments totaling ~~$6,841~~$7,140 million and $6,507 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Exelon and Generation									Exelon and Generation
	Three Months Ended June 30,					Six Months Ended June 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011		2012		2011			2012		2011
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)	$	(96	)	$	28	$	150	$	140	$	202	$	(363	)	$	352	$	(223	)
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)		(35	)		11		30		54		71		(141	)		101		(88	)

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

See Note 2 of the Exelon 2011 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning. On September 1, 2010, Generation completed 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. See Note 12 of the Exelon 2011 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities

transferred in the transaction. On July 14, 2011, four people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. If the plaintiffs prevail on the merits of their claims, some or all of the NDT funds may no longer be available to ZionSolutions for decommissioning Zion Station, in which case, the contractual arrangement would require ZionSolutions to utilize a line of credit to complete the decommissioning. In addition, the appointment of a NDT fund trustee in this matter could impact Generation’s future decommissioning activities at other stations by setting a precedent for the appointment of trustees for NDT funds. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. The matter is currently under review by the court.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, 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’s 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’s 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 customers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and has a liability of approximately ~~$67~~$78 million, which is included within the nuclear decommissioning ARO at ~~June~~September 30, 2012. 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 ~~June~~September 30, 2012, the carrying value of the Zion Station pledged assets and the payable to ~~ZionSolutions~~Zion Solutions was approximately ~~$650~~$631 million and ~~$604~~$582 million, respectively. The payable excludes a liability recorded within Exelon’s and 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 Exelon’s and Generation’s Consolidated Balance Sheets at ~~June~~September 30, 2012 and December 31, 2011 was ~~$141~~$160 million and $128 million, respectively.

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 31, 2011, Generation, in its NRC-required biennial decommissioning funding status report, provided data from which the NRC concluded that the amount of decommissioning funding as of December 31, 2010 for Limerick Unit 1 was less than the amount required by the NRC’s regulations. Generation performed the calculations again in early 2012, which reflected that the amount of decommissioning funding as of December 31, 2011 for Limerick Unit 1 was less than the amount required by the NRC’s regulations. In February 2012, Generation obtained a parent guarantee in the amount of $115 million to cover the NRC minimum funding assurance requirements for Limerick Unit 1 and informed the NRC that it had addressed the minimum funding issues by, among other things, obtaining the parent guarantee. In a letter dated June 28, 2012, the NRC advised Generation of the NRC’s determination that the amount of decommissioning financial assurance provided in Generation’s plan was equal to or greater than the minimum required under the NRC regulations and that Generation had provided reasonable assurance that funds would be available for the Limerick Unit 1 decommissioning process.

~~NRC regulations and that Generation had provided reasonable assurance that funds would be available for the Limerick Unit 1 decommissioning process.~~

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation’s defined benefit pension and other postretirement benefit plans and defined contribution savings plans. As of that date, the legacy Constellation pension and other postretirement benefit plans were remeasured using current assumptions including the discount rate.

During the first quarter of 2012, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2012. This valuation resulted in an increase to the pension and other postretirement benefit obligations of $86 million and $25 million, respectively. Additionally, accumulated other comprehensive loss increased by approximately $8 million (after tax) and regulatory assets increased by $98 million.

During the second quarter of 2012, Exelon received an updated valuation of legacy Constellation’s pension and postretirement benefit obligations to reflect actual census data as of the merger date. This valuation resulted in an increase and a decrease to the pension and other postretirement benefit obligations of $1 million and $19 million, respectively. Additionally, accumulated other comprehensive loss decreased by approximately $3 million (after-tax) and regulatory assets decreased by approximately $13 million.

As a result of employee severances related to the merger, a curtailment was triggered for certain legacy Constellation pension and other postretirement benefit plans in the second quarter of 2012. Accordingly, the benefit obligation and plan assets for those plans were remeasured using assumptions as of June 30, 2012, including updated discount rates, asset values, and planned changes to the method of obtaining prescription drug subsidies. The discount rates used to calculate the curtailed pension and other postretirement benefit plan obligations as of June 30, 2012 were 3.97% and 3.98%, respectively. ~~These discount rates were used to calculate the remainder of year costs for the curtailed plans.~~ The curtailment and associated remeasurement resulted in an increase and a decrease to the ~~unfunded status of the~~ pension and other postretirement benefit ~~plans~~obligations of $84 million and $32 million, respectively. Additionally, accumulated other comprehensive loss increased by approximately $6 million (after-tax) and regulatory assets increased by approximately $44 million. Exelon also recognized a $2 million curtailment gain for legacy Constellation’s other postretirement benefit plans in the second quarter of 2012, of which Generation recognized a $1 million curtailment gain.

Under Exelon’s and Constellation’s severance plans, certain severed employees were offered additional pension and other postretirement benefits. As a result, Exelon recorded contractual termination benefit charges of $20 million in the second quarter of 2012, of which Generation and BGE recorded $9 million and $3 million, respectively. BGE recorded its portion of the contractual termination benefit charge of $3 million along with $1 million that was billed to it by BSC as a regulatory asset, consistent with prior MDPSC precedent. ComEd recorded the $1 million of contractual termination benefit charge that was billed to it by BSC as a regulatory asset pursuant to EIMA.

~~The following tables present~~During the ~~components~~third quarter of ~~Exelon’s net periodic~~2012, Exelon announced plan design changes for certain other postretirement benefit ~~costs~~plans, requiring an interim remeasurement of the benefit obligation and assets for ~~the three and six months ended June~~those plans using assumptions as of September 30, 2012, ~~and 2011. The 2012 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 7.50% for all plans and~~including updated discount rates ~~of 4.74%~~ and ~~4.27%~~asset values. The discount rates used to calculate the other postretirement benefit plan obligations for legacy Exelon and Constellation ~~plans, respectively.~~were 3.93% and 3.72%, respectively, as of September 30, 2012. The ~~2012~~remeasurement resulted in an increase to the other postretirement benefit ~~cost is calculated using an expected long-term rate~~obligation, accumulated other comprehensive loss, and regulatory assets of $212 million, $68 million (after-tax), and $99 million, respectively. Additionally, Exelon recognized a $5 million curtailment gain in the third quarter of 2012 related to these plan design changes, of which Generation and BGE recognized a curtailment gain of $1 million and $3 million, respectively.

The following tables present the components of Exelon’s net periodic benefit costs for the three and nine months ended September 30, 2012 and 2011. The 2012 pension benefit cost for legacy Exelon plans was calculated using an expected long-term rate of return on plan assets of 7.50% and a discount rate of 4.74%. The 2012 pension benefit cost for legacy Constellation plans was calculated using an expected long-term rate of return on plan assets of 7.50% and discount rates of 4.27% and 3.97% for the period post-merger through June 30, 2012 and July 1, 2012 through September 30, 2012, respectively. The 2012 other postretirement benefit cost for legacy Exelon plans was calculated using an expected long-term rate of return on plan assets of 6.68% ~~for funded plans,~~ and a discount ~~rates~~rate of 4.80% ~~and 4.28%~~. The 2012 other postretirement benefit cost for legacy ~~Exelon~~Constellation plans was calculated using a discount rate of 4.28% and ~~Constellation plans,~~3.98% for the period post-merger through June 30, 2012 and July 1, 2012 through September 30, 2012, respectively. Legacy Constellation other postretirement benefit plans are not funded. As discussed above, discount rates of 3.97% and 3.98% will be used to calculate net periodic benefit cost beginning July 1, 2012 for the legacy Constellation pension and other postretirement benefit plans that were curtailed in the second quarter of 2012. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.


	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,						Pension Benefits Three Months Ended September 30,						Other Postretirement Benefits Three Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	74		$	53		$	39		$	35		$	76		$	53		$	38		$	36
Interest cost		179			163			54			51			181			162			53			52
Expected return on assets		(253	)		(234	)		(29	)		(28	)		(258	)		(235	)		(28	)		(27	)
Amortization of:
Transition obligation		—			—			2			3			—			—			2			2
Prior service cost (benefit)		3			3			(3	)		(10	)		5			4			(3	)		(10	)
Actuarial loss		115			82			19			17			117			83			19			16
Contractual termination benefit cost(a)		14			—			6			—
Settlement Charges														9			—			—			—
Curtailment gain		—			—			(2	)		—			—			—			(5	)		—

Net periodic benefit cost	$	132		$	67		$	86		$	68		$	130		$	67		$	76		$	69


	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,						Pension Benefits Nine Months Ended September 30,						Other Postretirement Benefits Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	135		$	106		$	76		$	71		$	211		$	159		$	114		$	107
Interest cost		343			325			104			103			524			487			157			155
Expected return on assets		(484	)		(469	)		(58	)		(56	)		(742	)		(704	)		(86	)		(83	)
Amortization of:
Transition obligation		—			—			6			5			—			—			8			7
Prior service cost (benefit)		7			7			(6	)		(19	)		12			11			(10	)		(29	)
Actuarial loss		221			165			38			33			338			248			58			49
Settlement Charges														9			—			—			—
Contractual termination benefit cost(a)		14			—			6			—			14			—			6			—
Curtailment gain		—			—			(2	)		—			—			—			(7	)		—

Net periodic benefit cost	$	236		$	134		$	164		$	137		$	366		$	201		$	240		$	206

The amounts below were included in capital additions and operating and maintenance expense during the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, for Generation’s, ComEd’s, PECO’s, BGE’s and BSC’s allocated portion of the pension and postretirement benefit ~~plans.~~plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and ~~curtailment gain recognized in the second quarter of 2012.~~settlement charges.


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
Pension and Postretirement Benefit Costs	2012		2011		2012		2011		2012		2011		2012		2011
Generation	$	94	$	61	$	175	$	123	$	85	$	64	$	259	$	187
ComEd		68		54		137		108		75		53		212		160
PECO		13		8		26		16		12		8		38		24
BGE(a)(b)		18		14		32		28		14		15		46		43
BSC(c)		25		12		42		24		20		11		63		36

During the fourth quarter of 2012, Exelon will record an additional settlement charge of approximately $17 million. This charge is triggered by lump sum payments made to executives during the fourth quarter of 2012.

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon expects to contribute ~~$83~~$77 million to its qualified pension plans in 2012, of which Generation, ComEd, and PECO will contribute ~~$51~~$46 million, $9 million, and ~~$12~~$13 million, respectively. Legacy Constellation’s 2011 pension contributions included an acceleration of estimated calendar year 2012 contributions. Therefore, BGE does not anticipate any qualified pension contributions in 2012. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $67 million in 2012, of which Generation, ComEd, PECO, and BGE will make payments of $9 million, $14 million, $1 million, and $1 million, respectively.

Unlike qualified pension plans, other postretirement plans are not subject to regulatory minimum contribution requirements. Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). In 2012, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans previously sponsored by Constellation and AmerGen, which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $318 million in 2012, of which Generation, ComEd, PECO, and BGE expect to contribute ~~$132~~$131 million, $116 million, ~~$34~~$33 million, and ~~$14~~$13 million, respectively. This total excludes $4 million in 2012 other postretirement benefit plan contributions by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012.

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.

Exelon has developed and implemented an investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. 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. This investment strategy would tend to result in a lower expected rate of return on plan assets in future years. Trust assets for Exelon’s other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2012		2011		2012		2011		2012		2011		2012		2011
Exelon	$	17	$	15	$	33	$	34	$	16	$	26	$	49	$	64
Generation		8		8		15		18		7		13		23		33
ComEd		5		4		9		10		5		8		14		18
PECO		2		2		4		4		2		3		5		7
BGE(a)		2		2		4		4		1		1		5		5
BSC(b)		1		1		2		2		1		2		3		6

On October 31, 2012, Generation notified PJM of its intention to permanently retire Schuylkill Generating Station Unit 1 by February 1, 2013, and Riverside Generating Station Unit 6 by June 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, Pennsylvania, which was placed in service in 1958. Riverside Unit 6 is a 115 MW peaking gas/kerosene unit located in Baltimore, Maryland, which was placed in service in 1970. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and declining revenue expectations. PJM has 30 days to review whether the proposed retirements of the units create transmission system reliability issues. Once PJM’s review is complete, Exelon will determine final retirement dates for the units. The impact of the early retirements will not have a material impact on Generation or Exelon’s results of operations, cash flows or financial position.

In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit Generation’s retirement of two of the units on May 31, 2011 and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; Cromby Unit 2 retired on December 31, 2011 and Eddystone Unit 2 on May 31, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery

during the reliability-must-run period for Eddystone Unit 2 was approximately $6 million. Such revenue was intended to recover total expected operating costs, plus a return on net assets, of the unit during the reliability-must-run period. In addition, Generation was reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 operated under the reliability-must-run agreement from June 1, 2011 until the May 31, 2012 retirement date. See Note 14 of the Exelon 2011 Form 10-K for additional information.

The following table presents the activity of severance obligations for the announced ~~Cromby~~Eddystone and ~~Eddystone~~Cromby retirements from December 31, 2011 through ~~June~~September 30, 2012:


Severance Benefits Obligation	Exelon and Generation			Exelon and Generation
Balance at December 31, 2011	$	7		$	7
Cash payments		(2	)		(2	)

Balance at June 30, 2012	$	5
Balance at September 30, 2012				$	5

14. Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At ~~June~~September 30, 2012, there were approximately 20 million shares authorized for issuance under the LTIP. For the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation’s 1995 Long-Term Incentive Plan, 2002 Senior Management Long-Term Incentive Plan, Amended and Restated 2007 Long-Term Incentive Plan, Amended and Restated Management Long-Term Incentive Plan and Executive Long-Term Incentive Plan (collectively and as amended, if applicable, the “Constellation Plans”). Stock-based awards granted under the Constellation Plans and held by Constellation employees were generally converted into outstanding Exelon stock-based compensation awards with the estimated fair value determined to be $71 million using the Black-Scholes model. Refer to Note 3 -— Merger and Acquisitions for further information regarding the merger transaction. Specifically, as of the merger closing: (1) Exelon converted 12,037,093 outstanding shares that were subject to Constellation stock options into 11,194,151 Exelon stock options valued at $65 million; and (2) Exelon converted 165,219 Constellation no-sale restricted stock units into 153,654 Exelon no-sale restricted stock units valued at $6 million.

Exelon generally grants most of its stock options in the first quarter of each year. In connection with the merger with Constellation, the Compensation Committee of Exelon’s Board of Directors elected to delay the annual equity award grant from January 2012 to the effective date of the merger on March 12, 2012, in order to ensure that a majority of eligible employees receive grants on the same date and at the same market price.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
Components of Stock-Based Compensation Expense	2012			2011			2012			2011			2012			2011			2012			2011
Performance share awards	$	10		$	6		$	26		$	12		$	5		$	6		$	32		$	17
Stock options		4			1			11			6			2			1			13			7
Restricted stock units		11			5			30			21			12			5			41			26
Other stock-based awards		1			1			2			2			1			1			3			3

Total stock-based compensation expense included in operating and maintenance expense		26			13			69			41			20			13			89			53
Income tax benefit		(10	)		(5	)		(26	)		(16	)		(8	)		(5	)		(34	)		(21	)

Total after-tax stock-based compensation expense	$	16		$	8		$	43		$	25		$	12		$	8		$	55		$	32

The following table presents stock-based compensation expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
Subsidiaries	2012		2011		2012		2011		2012		2011		2012		2011
Generation	$	9	$	5	$	24	$	19	$	9	$	6	$	33	$	24
ComEd		2		1		7		3		2		1		9		4
PECO		1		1		3		3		1		1		4		4
BGE(a)		1		—		3		—		1		—		4		—
BSC(b)		13		6		32		16		7		5		39		21

Total	$	26	$	13	$	69	$	41	$	20	$	13	$	89	$	53

There were no significant stock-based compensation costs capitalized during the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011.

Non-qualified stock options are granted under the LTIP with exercise prices equal to the fair market value of the underlying stock at the date of grant. Generally, the stock options vest ratably over a four-year vesting period and expire ten years from the date of grant.

The following table presents the weighted average assumptions used to value Exelon stock options at their grant date for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Dividend yield		5.28	%		4.84	%		5.28	%		4.84	%		5.28	%		4.84	%		5.28	%		4.84	%
Expected volatility		23.20	%		24.40	%		23.20	%		24.40	%		23.20	%		24.40	%		23.20	%		24.40	%
Risk-free interest rate		1.30	%		2.65	%		1.30	%		2.65	%		1.30	%		2.65	%		1.30	%		2.65	%
Expected life (years)		6.25			6.25			6.25			6.25			6.25			6.25			6.25			6.25

The assumptions above relate to Exelon stock options granted during the period and therefore do not include stock options that were converted in connection with the merger with Constellation during the ~~six~~nine months ended ~~June~~September 30, 2012.

The following table summarizes Exelon’s stock option activity for the ~~six~~nine months ended ~~June~~September 30, 2012:


	Shares			Weighted Average Exercise Price (per share)		Shares			Weighted Average Exercise Price (per share)
Balance of shares outstanding at December 31, 2011		11,553,761		$	48.49		11,553,761		$	48.49
Granted		2,372,000			39.66		2,372,000			39.66
Converted Constellation options		11,194,151			41.35		11,194,151			41.35
Exercised		(1,149,913	)		25.98		(1,575,275	)		26.57
Forfeited		(37,475	)		46.94		(28,142	)		44.88
Expired		(94,867	)		47.08		(488,434	)		48.59

Balance of shares outstanding at June 30, 2012		23,837,657		$	45.35
Balance of shares outstanding at September 30, 2012							23,028,061		$	45.61

Exercisable at June 30, 2012(a)		21,393,180		$	45.87
Exercisable at September 30, 2012(a)							20,962,469		$	46.08

The following table summarizes Exelon’s nonvested stock option activity for the ~~six~~nine months ended ~~June~~September 30, 2012:


	Shares			Weighted Average Exercise Price (per share)		Shares			Weighted Average Exercise Price (per share)
Nonvested at December 31, 2011(a)		877,050		$	48.66		877,050		$	48.66
Granted(b)		2,372,000			39.66		2,372,000			39.66
Converted Constellation options		11,194,151			41.35		11,194,151			41.35
Vested(b)(c)		(11,903,857	)		41.66		(11,889,175	)		41.39
Forfeited		(94,867	)		47.08		(488,434	)		48.59

Nonvested at June 30, 2012(a)		2,444,477		$	40.60
Nonvested at September 30, 2012(a)							2,065,592		$	40.60

At ~~June~~September 30, 2012, ~~$10~~$8 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of ~~2.7~~2.5 years.

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility.

The following table summarizes Exelon’s nonvested restricted stock unit activity for the ~~six~~nine months ended ~~June~~September 30, 2012:


	Shares			Weighted Average Grant Date Fair Value (per share)		Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2011(a)		1,074,484		$	48.08		1,074,484		$	48.08
Granted		1,087,572			40.03		1,283,292			39.93
Converted Constellation restricted stock		825,735			38.91		825,735			38.91
Vested		(317,940	)		43.60		(427,499	)		47.69
Forfeited		(32,829	)		43.71		(47,415	)		42.67
Undistributed vested awards(b)		(550,253	)		40.42		(602,276	)		40.53

Nonvested at June 30, 2012(a)		2,086,769		$	42.57
Nonvested at September 30, 2012(a)							2,106,321		$	42.27

At ~~June~~September 30, 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of ~~$54~~$58 million, which are included in common stock in Exelon’s Consolidated Balance Sheets. ~~In addition,~~As of September 30, 2012, Exelon had no obligations related to outstanding restricted stock units that will be settled in ~~cash of $1 million at June 30, 2012, which are included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheets.~~cash. During the three months ended ~~June~~September 30, 2012 and 2011, Exelon settled restricted stock units with a fair value totaling $2$4 million and $2$1 million, respectively. During the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, Exelon settled restricted stock units with a fair value totaling ~~$21~~$23 million and ~~$17~~$19 million, respectively. At ~~June~~September 30, 2012, ~~$64~~$54 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of ~~2.31~~2.08 years.

Performance share awards are granted under the LTIP with the 2012 performance share awards being settled in 50% common stock and 50% cash over the three-year vesting term. The 2011 performance share awards are being settled entirely in common stock over the three-year vesting term. The performance shares granted prior to 2011 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period.

These awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock ~~portion is considered an equity award with the 75% payout floor being valued based on Exelon’s stock price on~~

portion is considered an equity award with the 75% payout floor being valued based on Exelon’s stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon’s current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon’s current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance shares granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant.

The following table summarizes Exelon’s nonvested performance share awards activity for the ~~six~~nine months ended ~~June~~September 30, 2012:


	Shares			Weighted Average Grant Date Fair Value (per share)		Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2011(a)		346,848		$	45.37		346,848		$	45.37
Granted		1,248,005			39.73		1,249,932			39.73
Vested		(155,447	)		47.76		(159,194	)		47.66
Forfeited		(6,015	)		41.06		(113,761	)		39.79
Undistributed vested awards(b)		(203,512	)		40.22		(128,370	)		40.98

Nonvested at June 30, 2012(a)		1,229,879		$	40.21
Nonvested at September 30, 2012(a)							1,195,455		$	40.17

During the three months ended ~~June~~September 30, 2012 and 2011, the fair value of Exelon’s settled performance shares and payments made in cash were immaterial. During the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, Exelon settled performance shares with a fair value totaling ~~$19~~$22 million and $21 million, respectively, of which $3 million and $10 million was paid in cash, respectively. As of ~~June~~September 30, 2012, ~~$29~~$19 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of ~~2.5~~2.3 years.

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 LTIPs 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 (in millions) used in calculating diluted earnings per share:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011		2012		2011		2012		2011
Net income on common stock	$	286	$	620	$	486	$	1,288	$	296	$	601	$	782	$	1,889

Average common shares outstanding — basic		853		663		779		663		854		663		804		663
Assumed exercise of stock options, performance share awards and restricted stock		3		1		2		1		3		2		2		1

Average common shares outstanding — diluted		856		664		781		664		857		665		806		664

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1718 million and 13 million for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and 10 million and 9 million for the three and ~~six~~nine months ended ~~June~~September 30, 2011, 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 ~~June~~September 30, 2012. In 2008, Exelon management decided to defer indefinitely any share repurchases.

The following is an update to the current status of commitments and contingencies set forth in Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation’s and BGE’s 2011 Form 10-K.

As of ~~June~~September 30, 2012, Generation’s short- and long-term commitments relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following table:


	Net Capacity Purchases(a)		Power-Related Purchases(b)		Transmission Rights Purchases(c)		Purchased Energy from CENG		Total		Net Capacity Purchases(a)		Power-Related Purchases(b)		Transmission Rights Purchases(c)		Purchased Energy from CENG		Total
2012	$	255	$	32	$	18	$	460	$	765	$	111	$	8	$	8	$	148	$	275
2013		363		81		32		653		1,129		375		92		32		699		1,198
2014		352		45		26		411		834		352		62		26		451		891
2015		350		12		13		—		375		350		23		13		—		386
2016		264		5		2		—		271		266		9		2		—		277
Thereafter		664		6		36		—		706		672		8		36		—		716

Total	$	2,248	$	181	$	127	$	1,524	$	4,080	$	2,126	$	202	$	117	$	1,298	$	3,743

As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase ~~agreement~~agreements with CENG ~~was~~were modified to be unit-contingent through the end of ~~its~~their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG’s nuclear plants at market prices. Generation discloses in the table commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Further, while CENG purchases from the balance sheet date through December 31, 2014 will eventually be purchased at a fixed price, only those portions of purchases that have been locked in with a fixed price have been disclosed in the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 555 — Investment in Constellation energy Nuclear Group, LLC for more details on this arrangement.

ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments as of ~~June~~September 30, 2012 are as follows:


			Expiration within														Expiration within
	Total		2012		2013		2014		2015		2016		2017 and beyond		Total		2012		2013		2014		2015		2016		2017 and beyond
ComEd
Electric supply procurement(a)	$	1,165	$	62	$	367	$	323	$	136	$	137	$	140	$	1,103	$	—	$	367	$	323	$	136	$	137	$	140
Renewable energy and RECs(b)		1,698		37		71		73		74		81		1,362		1,694		33		71		73		74		76		1,367
PECO
Electric supply procurement(c)		1,006		491		403		87		25		—		—		789		210		413		130		36		—		—
AECs		39		7		11		9		2		2		8		35		3		11		9		2		2		8
Curtailment services		7		7		—		—		—		—		—		4		4		—		—		—		—		—
BGE
Electric supply procurement(d)		1,509		509		730		270		—		—		—		1,171		201		707		263		—		—		—
Curtailment services		176		23		49		47		41		16		—		165		11		49		47		41		17		—

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation (and with respect to coal, commitments to sell coal) of which a portion relate to generating stations to be divested. See Note 3 — Mergers and Acquisitions for further details. PECO and BGE have commitments to purchase natural gas, related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of ~~June~~September 30, 2012, these net commitments were as follows:


			Expiration within														Expiration within
	Total		2012		2013		2014		2015		2016		2017 and beyond		Total		2012		2013		2014		2015		2016		2017 and beyond
Generation	$	8,335	$	674	$	1,129	$	1,140	$	1,172	$	757	$	3,463	$	8,668	$	263	$	1,252	$	1,298	$	1,279	$	929	$	3,647
PECO		433		94		96		68		53		31		91		412		55		114		68		53		31		91
BGE		642		64		92		70		52		51		313		657		44		125		72		52		51		313

The Registrants’ other purchase obligations as of ~~June~~September 30, 2012, which primarily represent commitments for services, materials and information technology, are as follows:


			Expiration within														Expiration within
	Total		2012		2013		2014		2015		2016		2017 and beyond		Total		2012		2013		2014		2015		2016		2017 and beyond
Exelon	$	1,115	$	534	$	181	$	139	$	95	$	30	$	136	$	1,049	$	434	$	217	$	135	$	94	$	32	$	137
Generation		606		302		105		95		71		5		28		555		248		110		91		69		8		29
ComEd		139		87		12		6		5		5		24		115		41		34		6		5		5		24
PECO		101		54		19		18		1		1		8		109		61		21		17		1		1		8
BGE		5		3		2		—		—		—		—		19		17		2		—		—		—		—

Generation has committed to the construction of a solar PV facility in Los Angeles County, California. Generation’s estimated commitments are ~~$362~~$192 million and ~~$446~~$650 million for the years 2012 and 2013, respectively. See Note 3 — Merger and Acquisitions for additional information.

Generation has committed to the construction of approximately 400 MW of new wind facilities during 2012, approximately 272MW of which is still under construction as of September 30, 2012. Generation’s estimated commitments for the wind turbines are approximately ~~$175~~$100 million for the remainder of 2012, primarily related to the procurement of the turbines.

Refer to Note 4 — Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd’s Infrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and Installation Plan and BGE’s comprehensive smart grid initiative.

The tables above do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 3 — Merger and Acquisitions for additional information on the merger commitments.

The Registrants’ commercial commitments as of ~~June~~September 30, 2012, representing commitments potentially triggered by future events were as follows:


	Exelon			Generation			ComEd			PECO			BGE			Exelon			Generation			ComEd			PECO			BGE
Letters of credit (non-debt)(a)	$	2,437		$	1,776		$	23		$	21		$	1		$	2,290		$	2,082		$	142		$	22		$	1
Guarantees		10,409	(b)		2,168	(c)		208	(d)		181	(e)		252	(f)		10,406	(b)		2,355	(c)		208	(d)		181	(e)		250	(f)
Nuclear insurance premiums(g)		2,098			2,098			—			—			—			2,098			2,098			—			—			—

Total commercial commitments	$	14,944		$	6,042		$	231		$	202		$	253		$	14,794		$	6,535		$	350		$	203		$	251

The Price-Anderson Act requires mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in $12.2 billion in funds available for public liability claims for any single incident at any power reactor site that exceeds the primary level of financial protection currently required ($375 million). Additionally, Generation is also required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation ~~was~~is $2.1 billion ~~at June 30, 2012,~~ which is included above in the Commercial Commitments table and which does not include the potential

maximum combined retrospective premium obligations of CENG. See the Nuclear Insurance section within Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation’s and BGE’s 2011 Form 10-K for additional details on Generation’s nuclear insurance premiums.

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, Generation 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 ~~June~~September 30, 2012 and is set to expire in 2014. The guarantee is included above in the Commercial Commitments table under Guarantees.

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 ~~June~~September 30, 2012. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire ~~by 2014.~~in 2013. The guarantee of $95 million is included above in the Commercial Commitments table under Guarantees.

~~General~~General. . The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location.

Pursuant to orders from the ICC, PAPUC and MDPSC, respectively, ComEd, PECO and BGE 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 second and third quarter of 2012, ComEd and PECO, respectively, completed an annual study of ~~its~~their future estimated MGP remediation requirements. The results of ~~this study~~these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased ~~its reserve~~their reserves and regulatory ~~asset~~assets by ~~$140 million.~~$146 million and $7 million, respectively. See Note 4 -— Regulatory Matters for additional information regarding the associated regulatory assets.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time of each study and the remediation standards currently required by the U.S. EPA. The increase in the reserve at ComEd was predominately tied to 6 sites with a total increase of approximately ~~$105~~$111 million. The change was driven by the completion of additional preliminary environmental investigations that identified increases in scope for the remediation of larger areas and to greater depths, along with the requirement for additional groundwater management not previously contemplated in prior studies. ComEd also obtained new information on scope requirements for several sites where another PRP is leading remediation efforts and that ComEd shares responsibility. Prior to completion of any significant clean up, each site remediation plan is approved by the Illinois EPA.

As of ~~June~~September 30, 2012 and December 31, 2011, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:


June 30, 2012	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
September 30, 2012					Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	357	$	297	$	351	$	307
Generation		51		—		35		—
ComEd		262		256		265		260
PECO		44		41		50		47
BGE						1		—

December 31, 2011	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation		Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	224	$	168	$	224	$	168
Generation		47		—		47		—
ComEd		127		121		127		121
PECO		50		47		50		47
BGE						—		—

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

Section 316(b) of the Clean Water ~~Act~~Act. . Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s and CENG’s power generation

facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. For Generation those facilities are C.P. Crane, Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, H.A. Wagner, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. See ITEM 2. PROPERTIES of the Exelon 2011 Form 10-K and ITEM 2. PROPERTIES of the Constellation 2011 Form 10-K for a description of these facilities.

On March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry.

In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non-use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost-effective. On July 18, 2012, the U.S. EPA announced that it had agreed to extend the court approved Settlement Agreement to extend the deadline to issue a final rule until June 27, 2013. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment.

Oyster ~~Creek~~Creek.. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would have required, 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. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek no later than December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon’s determination to cease generation operations no later than December 31, 2019, the NJDEP determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and the limited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, NJDEP determined that the existing measures at the plant represent the best technology available for the facility’s cooling water intake through cessation of generation operations.

On December 9, 2010, Generation executed an Administrative Consent Order (ACO) with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster Creek if the conditions of the ACO are satisfied. In accordance with the ACO, on December 21, 2011, the NJDEP agreed to issue a final NPDES permit that became effective on April 12, 2012 that does not require the construction of cooling towers or other closed-cycle cooling facilities. The ACO and the final permit apply only to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon’s other plants.

As a result of the decision and the ACO, the expected economic useful life of Oyster Creek was reduced by 10 years to correspond to Exelon’s current best estimate as to the timing of ceasing generation operations at the Oyster Creek unit in 2019. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the changes in decommissioning assumptions related to Generation’s asset retirement obligation over the remaining expected economic useful life of Oyster Creek.

Salem and Other Power Generation ~~Facilities~~Facilities.. 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, the operator of Salem, in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 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 be approximately $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment.

It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation’s other power generation facilities, as well as CENG’s, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG.

Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG’s generating facilities and its future results of operations, cash flows and financial position.

Groundwater ~~Contamination~~Contamination.. In October 2007, a subsidiary of Constellation entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 million to comply with the consent decree. As of ~~June~~September 30, 2012, approximately $18 million of these costs had been paid, resulting in a remaining liability at ~~June~~September 30, 2012 of $5 million.

Alleged Conemaugh Clean Streams Violation by PA ~~DEP~~DEP.. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station (CGS), violated the Pennsylvania Clean Streams Law. GenOn has been engaged in discussions with PA DEP and has reached agreement on a proposed Consent Order that will be submitted for court ~~approval.~~approval following a public comment period. Under the proposed Consent Order, GenOn will be obligated to pay a civil penalty of $500,000, of which Generation’s responsibility would be approximately $200,000.

Cross State Air Pollution ~~Rule~~Rule.. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO₂ and NO_x. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court’s July 11, 2008 opinion. On July 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. On July 7, 2011, the U.S. EPA published the final rule, now known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. The final rule maintains the January 1, 2012 and January 1, 2014 phase-in dates that were in the proposed Transport Rule. However, the CSAPR imposes tighter emissions caps than the proposed Transport Rule and includes six additional states under the summertime NO_x reduction requirements. These emissions limits may be further reduced as the U.S. EPA finalizes more restrictive ozone and particulate matter NAAQS in the 2012 — 2014 timeframe.

Under the CSAPR, Generation units will receive allowances based on historic heat input, intrastate, and limited interstate, trading of allowances is permitted, subject to certain limitations. The CSAPR restricts entirely the use of pre-2012 allowances. Existing SO₂ allowances under the ARP would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment charge 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 CSAPR regulations would restrict entirely the use of ARP SO₂ allowances beginning in 2012. As of ~~June~~September 30, 2012, Generation had $39 million of emission allowances carried at the lower of weighted average cost or market.

On October 6, 2011 and February 7, 2012, the U.S. EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to the CSAPR. On June 12, 2012, U.S. EPA issued its final technical corrections and associated updates to state emission budgets, and generating unit emission allowance allocations. On a related matter, on May 30, 2012, U.S. EPA issued its final rule with regard to electric generating unit regulation under the regional haze program. Under this final rule, states participating in the CSAPR trading programs will be allowed to use those programs in place of source-specific BART for sulfur dioxide and/or nitrogen oxide emissions from power plants that are subject to the regional haze rule

Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court’s consideration of the matter on the merits. The D.C. Circuit Court granted permission for Exelon, as well as a number of other parties, to intervene in the litigation in support of the rule. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR

in the interim. ~~Subsequently~~On August 21, 2012, a three-judge panel of the D.C. Circuit Court ~~ordered an expedited case management schedule that resulted in oral argument on April 13, 2012. It is unknown when the Court will issue its decision on the merits. Exelon believes~~held that the U.S. EPA had exceeded its authority in certain material aspects of CSAPR ~~is a valid exercise~~and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. On October 5, 2012, the DOJ, on behalf of the U.S. ~~EPA’s authority and discretion under~~EPA, filed a petition for a re-hearingen banc (i.e., before all the ~~Clean Air Act.~~D.C. Circuit Court judges) of the panel’s decision. On the same date Exelon joined with other industry members in a petition for anen banc review.

EPA Mercury and Air Toxics Standards (MATS).. On April 16, 2012, the MATS rule to reduce emissions of toxic air pollutants from electric generating units (EGUs) became final. The MATS rule also finalized the new source performance standards for EGUs. The MATS rule resulted from a finding by the D.C. Circuit Court that the prior rule, known as the Clean Air Mercury Rule (CAMR), was invalid because it did not regulate mercury as

a HAP. The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will cause oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon was granted permission by the Court to intervene in support of the rule. A decision by the Court is not expected until some time in 2013.

Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS. In addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation — Brandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for the merger, Exelon agreed to divest these generating stations. It is anticipated that these plants are well positioned to comply with CSAPR and MATS, since Maryland has adopted SO₂, NO_x, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.

In addition, as of ~~June~~September 30, 2012, Exelon had a ~~$670~~$678 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, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.

~~NAAQS~~NAAQS. . The U.S. EPA previously announced that it would complete a review of NAAQS in the 2011 — ~~2012~~2014 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide, ozone, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations. In July 2012, the D.C. Circuit Court issued separate rulings upholding tightened NAAQs established by the U.S. EPA in 2010 for nitrogen dioxide and sulfur dioxide. The rulings clear the way for the U.S. EPA to continue work already underway with state and local agencies on implementing revised SIP’s designed to achieve or maintain the required air quality levels. To the extent not already impacted by ~~CSAPR~~CAIR (and in the future by CSAPR) and MATS, some power plants could be required to achieve further reductions of nitrogen dioxide and sulfur dioxide emissions.

In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in ~~2013.~~2014. Litigation of the ozone standard in the D.C. Circuit Court continues with an oral argument scheduled for November 2012. On June 14, 2012, the U.S. EPA proposed revisions to the Agency’s particulate matter NAAQS and indicated that it would issue a final rule by December 14, 2012. In its proposed rule, the U.S. EPA has requested public comment on a lowered annual PM2.5 standard, as well as proposed a new secondary NAAQS to improve urban visibility. The U.S. EPA ~~indicates~~indicated in its proposals that by 2020 it expects most areas of the country will be in attainment of the new NAAQS based on currently expected regulations, such as the MATS regulation. It is unclear if the vacatur of the CSAPR, ~~and MATS~~one of the regulations ~~among others.~~that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA’s view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020.

Notices and Finding of Violations Related to Electric Generation ~~Stations~~Stations.. On August 6, 2007, ComEd received a 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 generating stations are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

In 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 March 16, 2011, the U.S. District Court granted ComEd’s motion to dismiss the May 2010 complaint. On January 3, 2012, upon leave of the U.S. District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals.

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, in light of the District Court decision the likelihood of loss is remote. Therefore, no reserve has been established. Further, Generation believes, that it would be reimbursed by Midwest Generation and EME for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME. On July 31, 2012, Edison International (EI), the parent company of EME, stated that EME may not have sufficient liquidity to repay unsecured debt due in June 2013. ~~Furthermore,~~In addition, on November 1, 2012, EI stated that ~~should EME~~ there is no assurance that interest payments due on the unsecured debt would

be ~~unable~~paid as required on November 15, 2012, and that failure to ~~restructure its debt, it would need to reorganize~~pay will likely result in EME’s filing for protection under Chapter 11 of the U.S. Bankruptcy ~~Code.~~code. In that event, ComEd and Generation would be an unsecured ~~creditor~~creditors with respect to any indemnification obligations owed by EME and Midwest Generation.

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. 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 approximately $42 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. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review.

In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the SFS that could take up to one year to complete, and it is unknown when the U.S EPA will propose a remedy for public comment. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. 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.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately ~~$100~~$90 million. The DOJ and the PRPs have agreed to toll the statute of limitations until August ~~2012~~2013 so that settlement discussions can proceed. ~~It is likely that the parties will agree to extend the statute of limitations until August 2013.~~ Based on Exelon’s preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the “Exelon defendants”). The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants’ negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits and the motions are still before the Court. Exelon remains potentially liable due to its indemnification responsibilities of Cotter described above. Due to the early stage of the litigation, Exelon is unable to determine the extent of its potential liability, if any.

68^th Street ~~Dump~~Dump.. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The potentially responsible parties submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. The U.S. EPA is expected to make a final selection of one of the alternatives in 2012. ~~Since the U.S. EPA~~Based on Exelon’s preliminary review, it appears probable that Exelon has ~~not selected the remedy~~liability and ~~the allocation~~has established an appropriate accrual for its share of the estimated clean-up ~~costs among the PRPs has not been determined, an estimate of the range of BGE’s possible loss, if any, cannot be determined.~~costs. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site.

Sauer ~~Dump~~Dump. . On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, MD. The U.S. EPA offered BGE and three other PRPs the opportunity

to conduct an environmental investigation and present cleanup recommendations at the site. The letter provided 60 days for the PRPs to decide whether or not to participate in the investigation. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On July 30, 2012, BGE along with the three other named PRP’s provided the U.S. EPA with a “Good Faith Offer” along with a proposed Settlement Agreement to conduct a Remedial Investigation and a Feasibility Study at the Site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The PRPs will seek to reach agreement with the U.S. EPA to conduct the investigation. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s possible loss, if any, cannot be determined.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels. 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. Consequently, 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 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 has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) 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 (the Tailoring Rule) 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 became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit

thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in aper curiam decision, dismissed industry and state petitions challenging the U.S. EPA’s Tailoring Rule based on petitioners’ lack of standing. Further, in the same decision, the Court denied all challenges to U.S. EPA’s endangerment finding, and the Agency’s “Tailpipe Rule” for cars and light trucks. In August 2012, several industry parties filed petitions for anen banc rehearing of the Agency’s GHG regulations with the D.C. Circuit Court. On September 6, 2012 the Circuit Court ordered the U.S. EPA, intervening environmental groups, and some states to reply to the industry petitions.

On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO₂ emissions to a thirty-year average of less than 1000 pounds per MWh (less than 1800 pounds per MWh for the first ten years and less than 600 pounds per MWh thereafter). Under the PSD 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. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants.

Except to the extent noted below, the circumstances set forth in Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation’s and BGE’s 2011 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. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At ~~June~~September 30, 2012 and December 31, 2011, Generation had reserved approximately ~~$65~~$64 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of ~~June~~September 30, 2012, approximately ~~$13~~$14 million of this amount related to ~~167~~170 open claims presented to Generation, while the remaining ~~$52~~$50 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 ~~three months ended June 30,~~second quarter of 2012, Generation increased its reserve by approximately $19 million, primarily due to increased actual and projected number and severity of claims.

BGE.Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

Approximately 480 individuals who were never employees of BGE or Generation have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and Generation in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Generation and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

Discovery begins in these cases once they are placed on the trial docket. At present, none of the pending cases are set for trial. Given the limited discovery, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the possible loss relating to these ~~claims.~~claims; as such, no accrual has been made. The specific facts not known include:

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

CENG is currently in negotiations with the DOE to recover damages caused by the DOE’s failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Nine Mile Point nuclear power plant. Any funds received from the DOE related to costs incurred prior to November 6, 2009 will belong to Generation. Generation has recorded a pre-acquisition contingent asset of approximately ~~$25~~$16 million related to its share of the potential settlement. See Note 3 — Mergers and Acquisitions for additional information on the merger.

Federal Energy Regulatory Commission Investigation (Exelon and Generation)

On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation’s power trading activities in and around the New York ISO from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC

investigation. Under the settlement, Constellation agreed to pay a $135 million civil penalty and $110 million in disgorgement. The disgorgement amount will be disbursed in two ways. First, Constellation will provide $1 million each to six U.S. regional grid operators for the purpose of improving their surveillance and analytic capabilities. The remainder of the disgorgement amount was deposited in a fund that will be administered by a FERC ALJ. State agencies in New York, New England and PJM (the regional grid operator for 13 states and the District of Columbia) will be eligible to make claims against the fund on behalf of electric energy consumers in those states.

During the ~~six~~nine months ended ~~June~~September 30, 2012, Generation recorded expense of $195 million in operating and maintenance expense with the remaining $50 million recorded as a Constellation pre-acquisition contingency. As of ~~June~~September 30, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 3 — Merger and Acquisitions for additional information on the merger.

The Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd’s service territory, as well as for five other storm systems that affected ComEd’s customers during June and July 2011 (“Summer 2011 Storm

Docket”). The ICC is currently conducting a proceeding to assess ComEd’s request. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non-consequential damages, and the local governments in the areas in which those customers are located could seek recovery of emergency and contingency expenses. On January 27, 2012, the ICC Staff and the Illinois Attorney General (AG) filed testimony in the ICC proceeding. They both disagreed with ComEd’s interpretation that the statute does not apply to the interruptions caused by the 2011 storms. The ICC witness supported granting a waiver for three of the six storms, while the AG asserted that ComEd should be held responsible for the damages from all the storms.

A hearing in this proceeding was held on July 10-12, 2012. At the hearing, the ICC Staff witness, based on updated data provided by ComEd, now testified that ComEd should receive a waiver of liability in connection with five of the six storm systems in the Summer 2011 Storm Docket. As for the sixth storm system that struck on July 11, 2011 and affected more than 900,000 customers, the ICC Staff witness testified that 51,767 customers were affected by interruptions for which he felt a waiver should not be granted. Post-hearing briefing ~~is underway and expected to conclude by~~was concluded in September ~~13,~~ 2012. The Administrative Law Judge has not stated when he expects to issue a proposed Order.

In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (“February 2011 Blizzard Docket”). On February 14, 2012, the ICC Staff and the AG filed testimony in the proceeding. ICC staff recommended that the ICC issue ComEd a waiver based on the extreme weather conditions. The AG

took the same position as it had in the Summer 2011 Storm Docket noted above. A hearing on this proceeding was also held on July 10-12, 2012 and post hearing briefing is also underway. Additional active proceedings related to storms of lesser collective impact are also pending.

The ultimate outcomes of these proceedings are uncertain, and the amount of damages, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.

Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation’s June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements, including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants’ motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a

consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Exchange Act of 1934 and limiting the suit to those persons who purchased Debentures in the June 2008 offering. In August 2011, plaintiffs requested permission from the court to file a third amended complaint in an effort to attempt to revive the claims of the common shareholders. Constellation filed an objection to the plaintiffs’ request for permission to file a third amended complaint and, on March 28, 2012, the District Court of Maryland denied the plaintiffs’ request for permission to revive the claims of the common shareholders. Given that limited discovery has occurred, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, Exelon is unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on its financial results.

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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.

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

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


Three Months Ended June 30, 2012	Exelon			Generation			ComEd		PECO		BGE
Three Months Ended September 30, 2012													Exelon			Generation			ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units(a)	$	50		$	50		$	—	$	—	$	—	$	33		$	33		$	—	$	—	$	—
Non-Regulatory Agreement Units(a)		19			19			—		—		—		10			10			—		—		—
Net unrealized losses on decommissioning trust funds —
Net unrealized gains on decommissioning trust funds —
Regulatory Agreement Units		(97	)		(97	)		—		—		—		202			202			—		—		—
Non-Regulatory Agreement Units		(35	)		(35	)		—		—		—		71			71			—		—		—
Net unrealized gains on pledged assets —
Zion Station decommissioning		4			4			—		—		—		22			22			—		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		31			31			—		—		—		(208	)		(208	)		—		—		—

Total decommissioning-related activities		(28	)		(28	)		—		—		—		130			130			—		—		—

Investment income		6			1			—		1		3		5			1			—		—		3
Long-term lease income		7			—			—		—		—		7			—			—		—		—
Interest income related to uncertain income tax positions		14			—			1		—		—		—			1			1		—		—
Credit facility termination fees		(42	)		(42	)		—		—		—		(43	)		(43	)		—		—		—
AFUDC — Equity		3			—			—		1		3		4			—			1		1		2
Other		(3	)		(7	)		2		—		1		(2	)		(6	)		3		1		—

Other, net	$	(43	)	$	(76	)	$	3	$	2	$	7	$	101		$	83		$	5	$	2	$	5


Six Months Ended June 30, 2012	Exelon			Generation			ComEd			PECO		BGE
Three Months Ended September 30, 2011														Exelon			Generation			ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units(a)	$	110		$	110		$	—		$	—	$	—
Non-Regulatory Agreement Units(a)		67			67			—			—		—
Net unrealized gains on decommissioning trust funds —
Net realized income on decommissioning trust funds(a)
Regulatory Agreement Units		150			150			—			—		—	$	16		$	16		$	—	$	—	$	—
Non-Regulatory Agreement Units		30			30			—			—		—		13			13			—		—		—
Net unrealized gains on pledged assets —
Net unrealized losses on decommissioning trust funds
Regulatory Agreement Units															(363	)		(363	)		—		—		—
Non-Regulatory Agreement Units															(141	)		(141	)		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning		38			38			—			—		—		(4	)		(4	)		—		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		(245	)		(245	)		—			—		—		281			281			—		—		—

Total decommissioning-related activities		150			150			—			—		—		(198	)		(198	)		—		—		—
									��
Investment income		10			—			1			2		6		1			—			—		1		3
Long-term lease income		15			—			—			—		—		7			—			—		—		—
Interest income related to uncertain income tax positions		14			—			—			—		—		7			—			12		—		—
Credit facility termination fees		(42	)		(42	)		—			—		—
AFUDC — Equity		7			—			—			2		6		4			—			2		2		4
Bargain purchase gain related to Wolf Hollow acquisition															36			36			—		—		—
Other		(2	)		(5	)		6			1		1		1			(2	)		2		—		1

Other, net	$	152		$	103		$	7		$	5	$	13	$	(142	)	$	(164	)	$	16	$	3	$	8


Six Months Ended June 30, 2011	Exelon			Generation			ComEd		PECO			BGE
Nine Months Ended September 30, 2011															Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds(a)
Regulatory Agreement Units	$	81		$	81		$	—	$	—		$	—		$	97		$	97		$	—	$	—		$	—
Non-Regulatory Agreement Units		26			26			—		—			—			39			39			—		—			—
Net unrealized gains on decommissioning trust funds
Net unrealized losses on decommissioning trust funds
Regulatory Agreement Units		140			140			—		—			—			(223	)		(223	)		—		—			—
Non-Regulatory Agreement Units		54			54			—		—			—			(88	)		(88	)		—		—			—
Net unrealized income on pledged assets
Zion Station decommissioning		45			45			—		—			—			41			41			—		—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(221	)		(221	)		—		—			—			60			60			—		—			—

Total decommissioning-related activities		125			125			—		—			—			(74	)		(74	)		—		—			—

Investment income		2			—			—		2			7			3			—			—		3			10
Long-term lease income		14			—			—		—			—			21			—			—		—			—
Interest income related to uncertain income tax positions		46			33			1		1			—			53			33			13		1			—
AFUDC — Equity		9			—			4		6			7			14			—			6		8			11
Bargain purchase gain related to Wolf Hollow acquisition																36			36			—		—			—
Other		—			(6	)		3		(1	)		(1	)		1			(7	)		5		(1	)		1

Other, net	$	196		$	152		$	8	$	8		$	13		$	54		$	(12	)	$	24	$	11		$	22

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


Nine Months Ended September 30, 2012											Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment											$	1,263	$	540	$	396	$	154	$	184
Regulatory assets												89		—		62		7		34
Amortization of intangible assets												24		24		—		—		—
Amortization of energy contract assets and liabilities(a)												731		812		—		—		—
Nuclear fuel(a)												628		628		—		—		—
Asset retirement obligation accretion(b)												174		174		—		—		—

Total depreciation, amortization, accretion and depletion											$	2,909	$	2,178	$	458	$	161	$	218


Six Months Ended June 30, 2011	Exelon		Generation		ComEd		PECO		BGE
Nine Months Ended September 30, 2011											Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	629	$	277	$	248	$	93	$	113	$	947	$	416	$	374	$	141	$	170
Regulatory assets		27		—		22		5		31		40		—		31		9		35
Nuclear fuel(a)		355		355		—		—		—		556		556		—		—		—
Asset retirement obligation accretion(b)		103		103		—		—		—		159		159		—		—		—

Total depreciation, amortization and accretion	$	1,114	$	735	$	270	$	98	$	144	$	1,702	$	1,131	$	405	$	150	$	205

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the ~~six~~nine months ended ~~June~~September 30, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of ~~$68~~$75 million, ~~$34~~$45 million and ~~$34~~$30 million, respectively, and reimbursements of ~~$65~~$85 million, ~~$46~~$55 million and ~~$19~~$30 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. For the ~~six~~nine months ended ~~June~~September 30, 2011, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of ~~$34~~$47 million, ~~$19~~$29 million and ~~$15~~$18 million, respectively, and reimbursements of ~~$54~~$86 million, ~~$26~~$45 million and ~~$28~~$41 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. See Note 4 — Regulatory Matters for additional information regarding the DOE SGIG.

The following tables provide additional information about assets and liabilities of the Registrants as of ~~June~~September 30, 2012 and December 31, 2011.


June 30, 2012	Exelon			Generation			ComEd		PECO		BGE
September 30, 2012													Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	11,367	(a)	$	5,526	(a)	$	2,844	$	2,731	$	2,549	$	11,890	(a)	$	5,910	(a)	$	2,906	$	2,765	$	2,579
Accounts receivable:
Allowance for uncollectible accounts		303			91			78		102		32		310			85			81		109		35

December 31, 2011	Exelon			Generation			ComEd		PECO		BGE		Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	10,959	(b)	$	5,313	(b)	$	2,750	$	2,662	$	2,465	$	10,959	(b)	$	5,313	(b)	$	2,750	$	2,662	$	2,465
Accounts receivable:
Allowance for uncollectible accounts		199			29			78		92		38		199			29			78		92		38

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income

criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $21 million as of ~~June~~September 30, 2012 and December 31, 2011. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 of the Exelon 2011 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at ~~June~~September 30, 2012 of $18 million consists of $1 million, $4 million and $13 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2011 of $17 million consists of $1 million, $3 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of ~~June~~September 30, 2012 and December 31, 2011 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on their payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 of the Exelon 2011 Form 10-K.

The following tables provide information about accumulated OCI (loss) recorded (after tax) within the Consolidated Balance Sheets of the Registrants as of ~~June~~September 30, 2012 and December 31, 2011:


June 30, 2012	Exelon			Generation			ComEd			PECO		BGE
September 30, 2012														Exelon			Generation			ComEd			PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	547		$	901		$	—		$	—	$	—	$	459		$	730		$	—		$	—	$	—
Pension and non-pension postretirement benefit plans		(2,864	)		—			—			—		—		(2,887	)		—			—			—		—
Net unrealized losses on foreign currency translation		(2	)		(2	)		—			—		—
Other comprehensive income — equity investment in CENG		6			6			—			—		—		23			23			—			—		—
Unrealized gain (loss) on marketable securities		—			(1	)		—			1		—		—			(1	)		—			1		—

Total accumulated other comprehensive income (loss)	$	(2,313	)	$	904		$	—		$	1	$	—	$	(2,405	)	$	752		$	—		$	1	$	—


December 31, 2011	Exelon			Generation			ComEd			PECO		BGE		Exelon			Generation			ComEd			PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	488		$	915		$	—		$	—	$	—	$	488		$	915		$	—		$	—	$	—
Pension and non-pension postretirement benefit plans		(2,938	)		—			—			—		—		(2,938	)		—			—			—		—
Unrealized loss on marketable securities		—			—			(1	)		—		—		—			—			(1	)		—		—

Total accumulated other comprehensive income (loss)	$	(2,450	)	$	915		$	(1	)	$	—	$	—	$	(2,450	)	$	915		$	(1	)	$	—	$	—

Exelon has nine reportable segments, ComEd, PECO, BGE and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and an aggregate of other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation’s expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income.

The foundation of Generation’s six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an Independent System Operator (ISO) / Regional Transmission Operator (RTO) and/or North American Electric Reliability Corporation (NERC) region. Descriptions of each of Generation’s six reportable segments are as follows:

Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these regional reportable segments. Exelon and Generation evaluate the performance of Generation’s power marketing activities 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, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements. Generation’s other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy

efficiency and demand response, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, are not allocated to regions. Further, Generation’s compensation under the reliability-must-run rate schedule, results of operations from the clean-coal assets held for sale; Brandon Shores, Wagner, and C.P. Crane, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 is as follows:


	Generation(a)		ComEd		PECO		BGE		Other(b)			Intersegment Eliminations			Exelon		Generation(a)		ComEd		PECO		BGE		Other(b)			Intersegment Eliminations			Exelon
Total revenues(c):
2012	$	3,753	$	1,281	$	715	$	616	$	363		$	(774	)	$	5,954	$	4,017	$	1,484	$	806	$	720	$	336		$	(798	)	$	6,565
2011		2,455		1,444		842		—		187			(432	)		4,496		2,821		1,784		946		—		206			(503	)		5,254
Intersegment revenues(d):
2012	$	408	$	1	$	1	$	2	$	362		$	(774	)	$	—	$	459	$	—	$	1	$	4	$	334		$	(798	)	$	—
2011		246		—		—		—		186			(432	)		—		304		1		2		—		203			(503	)		7
Net income (loss):
2012	$	165	$	42	$	80	$	16	$	(14	)	$	—		$	289	$	87	$	90	$	123	$	—	$	(3	)	$	—		$	297
2011		443		114		83		—		(19	)		—			621		386		112		105		—		(1	)		—			602
Total assets:
June 30, 2012	$	41,087	$	22,585	$	9,204	$	7,200	$	10,163		$	(12,805	)	$	77,434
September 30, 2012																	$	41,090	$	22,471	$	9,661	$	7,504	$	10,150		$	(12,523	)	$	78,353
December 31, 2011		27,433		22,638		9,156		—		6,162			(10,394	)		54,995		27,433		22,638		9,156		—		6,162			(10,394	)		54,995


	2012							2011								2012									2011
	Revenues from external customers(a)		Intersegment revenues			Total Revenues		Revenues from external customers(a)			Intersegment revenues		Total Revenues			Revenues from external customers(a)			Intersegment revenues			Total Revenues			Revenues from external customers(a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	1,433	$	(28	)	$	1,405	$	994		$	—	$	994		$	1,428		$	(11	)	$	1,417		$	1,032	$	—	$	1,032
Midwest		1,193		8			1,201		1,339			—		1,339			1,193			7			1,200			1,385		—		1,385
New England		296		32			328		3			—		3			390			1			391			2		—		2
New York		166		(22	)		144		—			—		—			183			2			185			—		—		—
ERCOT		412		1			413		101			—		101			532			1			533			307		—		307
Other Regions(b)		219		25			244		53			—		53			317			12			329			77		—		77

Total Revenues for Reportable Segments	$	3,719	$	16		$	3,735	$	2,490		$	—	$	2,490		$	4,043		$	12		$	4,055		$	2,803	$	—	$	2,803

Other(c)		34		(13	)		21		(35	)		—		(35	)		(35	)		(3	)		(38	)		18		—		18

Total Generation Consolidated Operating Revenues	$	3,753	$	3		$	3,756	$	2,455		$	—	$	2,455		$	4,008		$	9		$	4,017		$	2,821	$	—	$	2,821


	2012							2011								2012									2011
	RNF from external customers(a)		Intersegment RNF			Total RNF		RNF from external customers(a)			Intersegment RNF		Total RNF			RNF from external customers(a)			Intersegment RNF			Total RNF			RNF from external customers(a)			Intersegment RNF		Total RNF
Mid-Atlantic	$	911	$	(28	)	$	883	$	819		$	—	$	819		$	919		$	(11	)	$	908		$	835		$	—	$	835
Midwest		756		8			764		887			—		887			723			7			730			852			—		852
New England		28		32			60		2			—		2			80			1			81			1			—		1
New York		61		(22	)		39		—			—		—			11			2			13			—			—		—
ERCOT		118		1			119		(14	)		—		(14	)		158			—			158			103			—		103
Other Regions(b)		9		25			34		3			—		3			30			12			42			(4	)		—		(4	)

Total Revenues net of purchased power and fuel expense for Reportable Segments	$	1,883	$	16		$	1,899	$	1,697		$	—	$	1,697		$	1,921		$	11		$	1,932		$	1,787		$	—	$	1,787

Other(c)		18		(16	)		2		(83	)		—		(83	)		(26	)		(11	)		(37	)		(37	)		—		(37	)

Total Generation Revenues net of purchased power and fuel expense	$	1,901	$	—		$	1,901	$	1,614		$	—	$	1,614		$	1,895		$	—		$	1,895		$	1,750		$	—	$	1,750


	Generation(a)		ComEd		PECO		BGE(b)			Other(c)			Intersegment Eliminations			Exelon		Generation(a)		ComEd		PECO		BGE(b)				Other(c)			Intersegment Eliminations			Exelon
Total revenues(d):
2012	$	6,492	$	2,670	$	1,590	$	668		$	714		$	(1,494	)	$	10,640	$	10,509	$	4,154	$	2,396	$	1,388			$	1,049		$	(2,291	)	$	17,205
2011		5,098		2,910		1,996		—			373			(926	)		9,451		7,919		4,694		2,942		—				579			(1,429	)		14,705
Intersegment revenues(e):
2012	$	774	$	1	$	2	$	3		$	715		$	(1,494	)	$	1	$	1,233	$	2	$	3	$	7			$	1,050		$	(2,291	)	$	4
2011		552		1		2		—			373			(926	)		2		856		2		4		—				576			(1,429	)		9
Net income (loss):																											��
2012	$	332	$	129	$	177	$	(50	)	$	(98	)	$	—		$	490	$	419	$	219	$	300	$	(50	)		$	(101	)	$	—		$	787
2011		938		183		210		—			(43	)		—			1,288		1,325		295		314		—				(45	)		—			1,889

On October 29, 2012, a category 1 hurricane, Hurricane Sandy, interrupted electric service delivery to more than 850,000 customers and 325,000 customers in PECO’s and BGE’s service territories, respectively. Restoration efforts will include significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies. PECO and BGE estimate that restoration efforts will result in approximately $49 million to $55 million and $33 million to $37 million of incremental operating and maintenance expense, respectively, and $32 million to $36 million and $13 million to $14 million of incremental capital expenditures, respectively, for the fourth quarter.

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

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

Exelon has nine reportable segments consisting of Generation’s six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and other regions in Generation), ComEd, PECO and BGE. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments.

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.

Exelon’s consolidated financial information includes the results of its four separate operating subsidiary registrants, Generation, ComEd, PECO and BGE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO and BGE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants other than itself.

Financial Results. The following consolidated financial results reflect the results of Exelon for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011. The 2012 financial results only include the operations of Constellation and BGE from the date of the merger with Constellation (the Merger), March 12, 2012, through ~~June~~September 30, 2012. All amounts presented below are before the impact of income taxes, except as noted.


	Three Months Ended June 30,																					Favorable (Unfavorable) Variance			Three Months Ended September 30,																					Favorable (Unfavorable) Variance
	2012																		2011						2012																		2011
	Generation			ComEd			PECO			BGE			Other			Exelon			Exelon						Generation			ComEd			PECO			BGE			Other			Exelon			Exelon
Operating revenues	$	3,753		$	1,281		$	715		$	616		$	(411	)	$	5,954		$	4,496		$	1,458		$	4,017		$	1,484		$	806		$	720		$	(462	)	$	6,565		$	5,254		$	1,311
Purchased power and fuel		1,852			587			296			285			(414	)		2,606			1,716			(890	)		2,122			678			326			373			(473	)		3,026			2,121			(905	)

Revenue net of purchased power and fuel(a)		1,901			694			419			331			3			3,348			2,780			568			1,895			806			480			347			11			3,539			3,133			406

Other operating expenses
Operating and maintenance		1,166			331			172			161			(1	)		1,829			1,226			(603	)		1,415			350			199			201			(9	)		2,156			1,413			(743	)
Depreciation and amortization		204			152			54			71			13			494			329			(165	)		207			157			55			68			13			500			332			(168	)
Taxes other than income		90			69			42			47			6			254			191			(63	)		109			81			48			48			4			290			207			(83	)

Total other operating expenses		1,460			552			268			279			18			2,577			1,746			(831	)		1,731			588			302			317			8			2,946			1,952			(994	)
Equity in loss of unconsolidated affiliates		(57	)		—			—			—			—			(57	)		—			(57	)
Equity in earnings of unconsolidated affiliates																										10			—			—			—			—			10			—			10

Operating income (loss)		384			142			151			52			(15	)		714			1,034			(320	)
Operating income																										174			218			178			30			3			603			1,181			(578	)

Other income and (deductions)
Interest expense, net		(85	)		(74	)		(31	)		(34	)		(32	)		(256	)		(182	)		(74	)		(85	)		(74	)		(32	)		(35	)		(20	)		(246	)		(182	)		(64	)
Other, net		(76	)		3			2			7			21			(43	)		101			(144	)		83			5			2			5			6			101			(142	)		243

Total other income and (deductions)		(161	)		(71	)		(29	)		(27	)		(11	)		(299	)		(81	)		(218	)		(2	)		(69	)		(30	)		(30	)		(14	)		(145	)		(324	)		179

Income (loss) before income taxes		223			71			122			25			(26	)		415			953			(538	)		172			149			148			—			(11	)		458			857			(399	)
Income taxes		58			29			42			9			(12	)		126			332			206			85			59			25			—			(8	)		161			255			94

Net income (loss)		165			42			80			16			(14	)		289			621			(332	)		87			90			123			—			(3	)		297			602			(305	)
Net (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(1	)		—			1			3			—			3			1			(2	)
Net (loss) income attributable to noncontrolling interests, preferred security dividends and preference stock dividends																										(4	)		—			1			4			—			1			1			—

Net income (loss) on common stock	$	166		$	42		$	79		$	13		$	(14	)	$	286		$	620		$	(334	)	$	91		$	90		$	122		$	(4	)	$	(3	)	$	296		$	601		$	(305	)


	Six Months Ended June 30,																					Favorable (Unfavorable) Variance			Nine Months Ended September 30,																					Favorable (Unfavorable) Variance
	2012																		2011						2012																		2011
	Generation			ComEd			PECO			BGE			Other			Exelon			Exelon						Generation			ComEd			PECO			BGE			Other			Exelon			Exelon
Operating revenues	$	6,492		$	2,670		$	1,590		$	668		$	(780	)	$	10,640		$	9,451		$	1,189		$	10,509		$	4,154		$	2,396		$	1,388		$	(1,242	)	$	17,205		$	14,705		$	2,500
Purchased power and fuel		2,896			1,208			707			352			(792	)		4,371			3,716			(655	)		5,018			1,886			1,033			727			(1,266	)		7,398			5,836			(1,562	)

Revenue net of purchased power and fuel(a)		3,596			1,462			883			316			12			6,269			5,735			534
Revenue net of purchased power and fuel (a)																										5,491			2,268			1,363			661			24			9,807			8,869			938

Other operating expenses
Operating and maintenance		2,340			650			375			222			206			3,793			2,449			(1,344	)		3,756			1,000			574			423			196			5,949			3,863			(2,086	)
Depreciation and amortization		357			300			107			90			22			876			656			(220	)		564			458			161			157			36			1,376			987			(389	)
Taxes other than income		164			144			74			57			9			448			394			(54	)		272			224			122			104			15			737			602			(135	)

Total other operating expenses		2,861			1,094			556			369			237			5,117			3,499			(1,618	)		4,592			1,682			857			684			247			8,062			5,452			(2,610	)
Equity in loss of unconsolidated affiliates		(79	)		—			—			—			—			(79	)		—			(79	)
Equity in losses of unconsolidated affiliates																										(69	)		—			—			—			—			(69	)		—			(69	)

Operating income (loss)		656			368			327			(53	)		(225	)		1,073			2,236			(1,163	)		830			586			506			(23	)		(223	)		1,676			3,417			(1,741	)

Other income and (deductions)
Interest expense, net		(138	)		(156	)		(62	)		(42	)		(53	)		(451	)		(363	)		(88	)		(223	)		(230	)		(94	)		(77	)		(73	)		(697	)		(545	)		(152	)
Other, net		103			7			5			8			29			152			196			(44	)		185			12			6			14			36			253			54			199


Total other income and (deductions)		(35	)		(149	)		(57	)		(34	)		(24	)		(299	)		(167	)		(132	)		(38	)		(218	)		(88	)		(63	)		(37	)		(444	)		(491	)		47

Income (loss) before income taxes		621			219			270			(87	)		(249	)		774			2,069			(1,295	)		792			368			418			(86	)		(260	)		1,232			2,926			(1,694	)
Income taxes		289			90			93			(38	)		(150	)		284			779			495			373			149			118			(37	)		(158	)		445			1,034			589

Net income (loss)		332			129			177			(49	)		(99	)		490			1,290			(800	)		419			219			300			(49	)		(102	)		787			1,892			(1,105	)
Net (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			2			4			—			4			2			(2	)
Net (loss) income attributable to noncontrolling interests, preferred security dividends and preference stock dividends																										(6	)		—			3			8			—			5			3			(2	)

Net income (loss) on common stock	$	334		$	129		$	175		$	(53	)	$	(99	)	$	486		$	1,288		$	(802	)	$	425		$	219		$	297		$	(57	)	$	(102	)	$	782		$	1,889		$	(1,107	)

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011.Exelon’s net income was ~~$286~~$296 million for the three months ended ~~June~~September 30, 2012 as compared to ~~$620~~$601 million for the three months ended ~~June~~September 30, 2011, and diluted earnings per average common

share were ~~$0.33~~$0.35 for the three months ended ~~June~~September 30, 2012 as compared to ~~$0.93~~$0.90 for the three months ended ~~June~~September 30, 2011.

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by ~~$568~~$406 million primarily due to the addition of BGE’s and Constellation’s financial results. BGE’s operating revenue net of purchased power and fuel expense was ~~$331~~$347 million for the three months ended ~~June~~September 30, 2012. Generation’s operating revenue net of purchased power and fuel expense increased by ~~$287~~$145 million ~~of which $261 million related~~primarily due to the New England, New York, ERCOT and Other Regions. These regions ~~were~~contributed

$195 million and did not previously have a significant ~~contributors to~~impact on Generation’s revenue net of purchased power and fuel expense prior to the Merger. Generation’s results were also favorably impacted by ~~$174~~$153 million of other activities, including retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities, and by ~~$64~~$73 million in the Mid-Atlantic region also

due to the addition of Constellation’s operations in 2012. Generation had mark-to-market gains of ~~$204~~$16 million in 2012 from economic hedging activities, net of intercompany eliminations, compared to ~~$124~~$91 million in mark-to-market losses in 2011. Offsetting these favorable impacts, Generation incurred ~~$412~~$257 million of amortization expense for the acquired energy contracts, net, recorded at fair value at the merger date. Also, revenues net of purchased power and fuel expense decreased by $123 million in the Midwest region due to lower realized power prices and lower capacity ~~revenues and increased nuclear fuel costs.~~revenues.

ComEd’s revenues net of purchased power and fuel expense decreased by ~~$34~~$46 million primarily due to ~~the discrete impacts of the 2012 distribution rate case order, partially offset by the~~decreased cost recovery for regulatory required programs ~~favorable weather~~ and ~~higher~~lower electric distribution rates effective, June ~~1, 2011. PECO’s operating revenues net of purchased power and fuel expense decreased by $15 million primarily as a result of unfavorable weather.~~20, 2012.

Operating and maintenance expense increased by ~~$603~~$743 million primarily due to the addition of BGE and Constellation. ~~Labor,~~In addition, operating and maintenance expense was unfavorably affected by the $278 million loss on the sale of three Maryland generating assets. Including Constellation and BGE, labor, other benefits, contracting and materials increased by $436 million and pension and ~~OPEB expense increased by $63 million and transaction costs and employee-related~~non-pension postretirement benefit expenses increased by ~~$32~~$73 million. In addition, ~~ComEd’s~~BGE incurred $40 million of storm costs during the three months ended September 30, 2012. Increased operating and maintenance expense ~~increased~~was partially offset by ~~$32~~decreased storm costs in the ComEd and PECO service territories of $57 million ~~as a result of the discrete impacts in 2011 from the 2010 Rate Case Order~~ and by $23 million, ~~related to~~respectively, and a decrease of $25 million at ComEd associated with regulatory required programs.

Depreciation and amortization expense increased by ~~$165~~$168 million primarily due to higher plant balances resulting from the addition of BGE’s and Constellation’s plant balances as well as ongoing capital expenditures ~~at Generation, ComEd and PECO.~~across the operating companies.

Equity in ~~losses~~earnings of unconsolidated affiliates was ~~$57~~$10 million primarily due to net income generated from Exelon’s equity investment in CENG, partially offset by the amortization of acquired energy contracts, net, and the basis difference of Generation’s ownership interest in CENG recorded at fair value at the merger date.

Interest expense increased by ~~$74~~$64 million due to an increase in debt obligations as a result of the ~~Merger.~~Merger and an increase in debt issued at Generation and BGE in 2012.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011.Exelon’s net income was ~~$486~~$782 million for the ~~six~~nine months ended ~~June~~September 30, 2012 as compared to ~~$1,288~~$1,889 million for the ~~six~~nine months ended ~~June~~September 30, 2011, and diluted earnings per average common share were ~~$0.62~~$0.97 for the ~~six~~nine months ended ~~June~~September 30, 2012 as compared to ~~$1.94~~$2.84 for the ~~six~~nine months ended ~~June~~September 30, 2011. Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by ~~$534~~$938 million primarily due to the addition of Constellation’s and BGE’s financial results. BGE’s operating revenue net of purchased power and fuel expense was ~~$316~~$661 million ~~for the six months ended, June~~from March 12, 2012 to September 30, 2012, which included the $113 million impact of the residential customer rate credit in connection with the Merger. Generation’s operating revenue net of purchased power and fuel expense increased by ~~$222~~$367 million ~~of which $356 million related~~primarily due to the New England, New York, ERCOT and Other Regions. These regions ~~were~~contributed $552 million and did not previously have a significant ~~contributors to~~on Generation’s revenue net of purchased power and fuel expense prior to the Merger. Generation’s results were also favorably ~~impacted~~affected by ~~$228~~$383 million of other activities, including retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities. Generation had mark-to-market gains of ~~$275~~$276 million in 2012 from economic hedging activities, net of intercompany eliminations, compared to ~~$272~~$363 million in mark-to-market losses in 2011. Offsetting these favorable impacts, Generation incurred ~~$534~~$793 million of

amortization expense for the acquired energy contracts, net, recorded at fair value at the merger date. Also, revenue net of purchased power and fuel expenses decreased by ~~$270 million and $79~~$394 million in the Midwest ~~and Mid-Atlantic regions, respectively,~~region due to lower realized power prices and lower capacity ~~revenues and increased nuclear fuel costs.~~revenues.

ComEd’s revenues net of purchased power and fuel expense increased by $57 million primarily due to the cost recovery for regulatory required programs and higher electric distribution rates effective, June 1, 2011, partially offset by the discrete impacts of the 2012 distribution rate case order. PECO’s operating revenues net of purchased power and fuel expense decreased by ~~$71~~$73 million primarily as a result of unfavorable ~~weather.~~weather and a decline in electric load.

Operating and maintenance expense increased by ~~$1,344~~$2,086 million primarily due to the addition of BGE and Constellation. ~~Labor,~~In addition, operating and maintenance expense was unfavorably affected by the $278 million loss on the sale of three Maryland generating assets. Including Constellation and BGE, labor, other benefits, contracting and materials increased by ~~$554~~$994 million, ~~transaction~~Constellation merger and integration costs ~~and employee-related expenses~~ increased by ~~$176~~$187 million, and pension and ~~OPEB~~non-pension postretirement benefits expense increased by ~~$94~~$170 million. In addition, Exelon incurred ~~$218~~$216 million in costs incurred as part of the Maryland order approving the Merger and costs of $195 million associated with a settlement with the FERC in March, ~~2012. ComEd’s~~2012, and BGE incurred $45 million of storm costs. Increased operating and maintenance expense ~~increased~~was partially offset by ~~$32~~decreased storm costs in the ComEd and PECO service territories of $78 million ~~as a result of the discrete impacts in 2011 from the 2010 Rate Case Order~~ and ~~by $41~~$31 million, ~~related to regulatory required programs.~~respectively.

Depreciation and amortization expense increased by ~~$220~~$389 million primarily due to higher plant balances resulting from the addition of BGE’s and Constellation’s plant balances as well as ongoing capital expenditures ~~at Generation, ComEd and PECO.~~across the operating companies.

Equity in losses of unconsolidated affiliates was ~~$79~~$69 million primarily due to the amortization of acquired energy contracts, net, and the basis difference of Generation’s ownership interest in CENG recorded at fair value at the merger ~~date.~~date, partially offset by net income generated from Exelon’s equity investment in CENG.

Interest expense increased by ~~$88~~$152 million due to an increase in debt obligations as a result of the ~~Merger.~~Merger and an increase in debt issued at Generation and BGE in 2012.

Exelon’s results for the ~~six~~nine months ended ~~June~~September 30, 2011 were favorably affected by certain income tax-related matters. In 2012, Exelon recorded a ~~$121~~$117 million (after tax) non-cash benefit to income tax expense as a result of a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes due to the merger. Exelon’s results were also favorably affected by a 2011 non-cash charge of $29 million (after tax) recorded for the remeasurement of deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation and for the updated long-term state tax apportionment.

For further detail regarding the financial results for the three and ~~six~~nine months ended ~~June~~September 30, 2012, 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 ~~June~~September 30, 2012 were ~~$522~~$658 million, or ~~$0.61~~$0.77 per diluted share, compared with adjusted (non-GAAP) operating earnings of ~~$697~~$743 million, or ~~$1.05~~$1.12 per diluted share, for the same period in 2011. Exelon’s adjusted (non-GAAP) operating earnings for the ~~six~~nine months ended ~~June~~September 30, 2012 were ~~$1,125~~$1,783 million, or ~~$1.44~~$2.21 per diluted share, compared with adjusted (non-GAAP) operating earnings of ~~$1,476~~$2,219 million, or ~~$2.22~~$3.34 per diluted share, for the same period in 2011. 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. 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 ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the same period in 2011:


	Three Months Ended June 30,												Three Months Ended September 30,
	2012						2011						2012						2011
(All amounts after tax)				Earnings per Diluted Share						Earnings per Diluted Share						Earnings per Diluted Share						Earnings per Diluted Share
Net Income	$	286		$	0.33		$	620		$	0.93		$	296		$	0.35		$	601		$	0.90
Mark-to-Market Impact of Economic Hedging Activities(a)		(123	)		(0.15	)		75			0.12			(19	)		(0.02	)		55			0.08
Unrealized (Gains) Losses Related to NDT Fund Investments(b)		19			0.02			(6	)		(0.01	)		(38	)		(0.04	)		76			0.12
Plant Retirement and Divestitures(c)		(1	)		—			10			0.02			193			0.22			2			—
Constellation Merger and Integration Costs(d)		67			0.08			15			0.02			36			0.04			11			0.02
Amortization of Acquired Contracts(e)		281			0.33			—			—
Amortization of Commodity Contract Intangibles(e)														187			0.21			—			—
Amortization of the Fair Value of Certain Debt(f)		(3	)		—			—			—			(3	)		—			—			—
Non-Cash Benefit Resulting from Reassessment of State Deferred Income Taxes(g)		(4	)		—			—			—
Recovery of Costs Resulting From Distribution Rate Case Order(h)		—			—			(17	)		(0.03	)
Other Acquisition Costs(g)														—			—			5			0.01
Wolf Hollow Acquisition(h)														—			—			(23	)		(0.03	)
Asset Retirement Obligation(i)														6			0.01			16			0.02

Adjusted (non-GAAP) Operating Earnings	$	522		$	0.61		$	697		$	1.05		$	658		$	0.77		$	743		$	1.12


	Six Months Ended June 30,												Nine Months Ended September 30,
	2012						2011						2012						2011
(All amounts after tax)				Earnings per Diluted Share						Earnings per Diluted Share						Earnings per Diluted Share						Earnings per Diluted Share
Net Income	$	486		$	0.62		$	1,288		$	1.94		$	782		$	0.97		$	1,889		$	2.84
Mark-to-Market Impact of Economic Hedging Activities(a)		(167	)		(0.21	)		164			0.25			(185	)		(0.23	)		219			0.34
Unrealized (Gains) Losses Related to NDT Fund Investments(b)		(17	)		(0.02	)		(30	)		(0.04	)		(54	)		(0.07	)		46			0.07
Plant Retirement and Divestitures(c)		7			0.01			27			0.04			200			0.25			29			0.04
Constellation Merger and Integration Costs(d)		180			0.23			15			0.02			211			0.26			26			0.04
Amortization of Acquired Contracts(e)		358			0.46			—			—
Amortization of Commodity Contract Intangibles(e)														545			0.68			—			—
Amortization of the Fair Value of Certain Debt(f)		(3	)		—			—			—			(7	)		(0.01	)		—			—
Reassessment of State Deferred Income Taxes(g)		(121	)		(0.16	)		—			—
Recovery of Costs Resulting From Distribution Rate Case Order(h)		—			—			(17	)		(0.03	)
Maryland Commitments(i)		227			0.29			—			—
FERC Settlement(j)		172			0.22			—			—
Other Acquisition Costs(k)		3			—			—			—
Non-Cash Charge Resulting from Illinois Tax Rate Change Legislation(l)		—			—			29			0.04
Other Acquisition Costs(g)														3			—			5			0.01
Wolf Hollow Acquisition(h)														—			—			(23	)		(0.03	)
Asset Retirement Obligation(i)														6			0.01			16			0.02
Reassessment of State Deferred Income Taxes(j)														(117	)		(0.15	)		—			—
Recovery of Costs Pursuant to the 2011 Distribution Rate Case Order(k)														—			—			(17	)		(0.03	)
Maryland Commitments(l)														227			0.28			—			—
FERC Settlement(m)														172			0.22			—			—
Non-Cash Charge Resulting from Illinois Tax Rate Change Legislation(n)														—			—			29			0.04

Adjusted (non-GAAP) Operating Earnings	$	1,125		$	1.44		$	1,476		$	2.22		$	1,783		$	2.21		$	2,219		$	3.34

(b)

Reflects the impact of (gains) losses for the three and ~~six~~nine months ended ~~June~~September 30, 2012 (net of taxes of ~~$(37)~~$(76) million and ~~$46~~$(122) million, respectively) and for the three and ~~six~~nine months ended ~~June~~September 30, 2011 (net of taxes of ~~$19~~$141 million and ~~$58~~$82 million, respectively) on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(c)

~~Primarily~~For 2012, primarily reflects the impact for the three and nine months ended September 30, 2012 (net of taxes of $120 million and $123 million, respectively) associated with the expected sale in the fourth quarter of 2012 of three generating stations associated with certain regulatory approvals for the merger. For 2011, primarily reflects incremental accelerated depreciation associated with the retirement of four fossil generating units and compensation for the three and ~~six~~nine months ended ~~June 30, 2012 (net of taxes of $1 million and $3 million, respectively)~~

~~and for the three and six months ended June~~September 30, 2011 (net of taxes of $7$2 million and ~~$17~~$19 million, respectively) for operating two of the units past their planned ~~May 31, 2011~~ retirement date under a FERC-approved reliability-must-run rate schedule. For 2012, also reflects revenues and operating expenses for the three and six months ended June 30, 2012 (net of taxes of $(2) million and $0 million, respectively) related to three generation facilities to be required to be sold within 180 days of the merger. See Note 13 of the Combined Notes to Consolidated Financial Statements and “Results of Operations — Generation” for additional detail related to the generating unit retirements.

(d)

Reflects certain costs incurred for the three and ~~six~~nine months ended ~~June~~September 30, 2012 (net of taxes of ~~$44~~$52 million and ~~$76~~$133 million, respectively) and for the three and nine months ended ~~June~~September 30, 2011 (net of taxes of ~~$10 million)~~$7 million and $17 million, respectively) associated with the Constellation merger including employee-related expenses and integration initiatives. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

(e)

Reflects the non-cash impact for the three and ~~six~~nine months ended ~~June~~September 30, 2012 (net of taxes of ~~$183~~$121 million and ~~$234~~$355 million, respectively) of the amortization of ~~acquired energy~~intangible assets, net, related to commodity contracts recorded at fair value at the merger date. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

(f)

Represents the non-cash amortization of certain debt for the three and nine months ended September 30, 2012 (net of taxes of $(2) ~~million)~~million and $(4) million, respectively) recorded at fair value at the merger date expected to be retired in 2013. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

(g)	Reflects certain costs incurred for the nine months ended September 30, 2012 associated with various acquisitions (net of taxes of $2 million).

(h)	Reflects a non-cash bargain purchase gain (negative goodwill) for the three and nine months ended September 30, 2011 in connection with the acquisition of Wolf Hollow, net of acquisition costs (net of taxes of $15 million).

(i)	Reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units for the three and nine months ended September 30, 2012 (net of taxes of $4 million) and for the three and nine months ended September 30, 2011 (net of taxes of $11 million).

(j)

Reflects a one-time, non-cash benefit related to a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional detail related to the impact of the Illinois tax rate change legislation.

~~(h)~~(k)

Reflects a one-time benefit in the second quarter of 2011 to recover previously incurred costs as a result of the May 2011 ICC rate order (net of taxes of $5 million). See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

~~(i)~~(l)

Reflects costs incurred for the ~~three~~nine months ended ~~June~~September 30, 2012 associated with the Constellation merger (net of taxes of $101 million) as part of the Maryland order approving the merger transaction. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

~~(j)~~(m)

Reflects costs incurred for the ~~six~~nine months ended ~~June~~September 30, 2012 (net of taxes of $23 million) as part of a settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions. See Note 16 of the Combined Notes to Consolidated Financial Statements for additional information.

~~(k)~~

~~Reflects certain costs incurred for the six months ended June 30, 2012 associated with various acquisitions (net of taxes of $2 million).~~

~~(l)~~(n)

Reflects a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional detail related to the impact of the Illinois tax rate change legislation.

On March 12, 2012, the Exelon and Constellation merger was completed. On the merger date, Constellation’s shareholders received 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Based on Exelon’s opening share price on March 12, 2012, Constellation shareholders and equity award holders received $7.4 billion in total equity value. The resulting company retained the Exelon name and is headquartered in Chicago.

Exelon has incurred and will continue to incur costs associated with evaluating, structuring and executing the merger transaction itself, meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former Constellation businesses into Exelon.

For the three and ~~six~~nine months ended ~~June~~September 30, 2012, expense has been recognized for costs incurred to achieve the merger as follows:


	Pre-tax Expense										Pre-tax Expense
	Three Months Ended June 30, 2012										Three Months Ended September 30, 2012
Merger and Integration Costs:	Generation(a)		ComEd		PECO		BGE(a)		Exelon(a)		Generation(a)		ComEd		PECO		BGE(a)		Exelon(a)
Transaction(b)	$	—	$	—	$	—	$	—	$	2	$	—	$	—	$	—	$	—	$	—
Maryland Commitments		—		—		—		—		—		—		—		—		—		—
Employee-Related(c)		39		—		2		—		43		12		—		2		—		15
Other(d)		55		—		2		2		66		67		—		1		1		72

Total	$	94	$	—	$	4	$	2	$	111	$	79	$	—	$	3	$	1	$	87


	Pre-tax Expense										Pre-tax Expense
	Six Months Ended June 30, 2012										Nine Months Ended September 30, 2012
Merger and Integration Costs:	Generation(a)		ComEd		PECO		BGE(a)		Exelon(a)		Generation(a)		ComEd		PECO		BGE(a)		Exelon(a)
Transaction(b)	$	—	$	—	$	—	$	—	$	52	$	—	$	—	$	—	$	—	$	52
Maryland Commitments		35		—		—		139		328		35		—		—		139		328
Employee-Related(c)		86		—		7		—		101		98		—		9		—		116
Other(d)		83		2		4		3		103		150		2		4		5		175

Total	$	204	$	2	$	11	$	142	$	584	$	283	$	2	$	13	$	144	$	671

As of September 30, 2012, Exelon projects incurring total additional merger-related ~~costs,~~expenses, primarily in 2012 and 2013, of approximately ~~$550 million, of which approximately $450 million is expected to be recognized as expense, and approximately $100 million is expected to be capitalized in connection with the integration of systems.~~$134 million.

In addition, pursuant to conditions set forth by the MDPSC in its approval of the merger transaction, Generation expects to incur capital expenditures of $95 million to $120 million for the requirement to cause

construction of a headquarters building in Baltimore for its competitive energy businesses (expected to be completed in 2 to 3 years) and up to $625 million for development of 285-300 MW of new electric generation facilities in Maryland (expected to be completed over the next ten years). The accounting treatment for the construction costs of the new headquarters building in Baltimore may vary depending on the structure of the transaction.

Exelon and Constellation have also agreed to enter into contracts to sell three Constellation generating stations located in PJM within 150 days (subsequently extended 30 days by DOJ) following the merger completion and will be required to complete the divestitures within 30 days after receipt of regulatory approvals. On August 8, 2012, a subsidiary of Generation reached an agreement to sell three Maryland generating stations and associated assets to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC. This pending sale is part of one of the post-merger actions required as part of merger regulatory approvals. See Note ~~3of~~3 of the Combined Notes to Consolidated Financial Statements for additional information on the merger and sale.

On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co.

Generation believes its nuclear generating facilities do not have the same operating risks as the Fukushima Daiichi plant because they meet the NRC’s requirement that specifies all plants must be able to withstand the most severe natural phenomena historically reported for each plant’s surrounding area, with a significant margin for uncertainty. In addition, Generation’s plants are not located in significant earthquake zones or in regions where tsunamis are a threat. Generation believes its nuclear generating facilities are able to shut down safely and keep the fuel cooled through multiple redundant systems specifically designed to maintain electric power when electricity is lost from the grid. Further, Generation’s nuclear generating facilities also undergo frequent scenario drills to ensure the proper function of the redundant safety protocols.

Since the events in Japan took place, Generation has continued to work with regulators and nuclear industry organizations to understand the events in Japan and apply lessons learned. ~~The~~Early on, the nuclear industry ~~has already taken~~took a number of specific steps to ~~respond. Generation has completed~~respond, including actions requested by the Institute of Nuclear Power Operations (INPO)~~, which included~~ to perform tests that verified ~~its~~Generation’s emergency equipment is available and functional, conduct walk-downs on its procedures related to critical safety equipment, ~~confirmation of~~confirm event response procedures and readiness to protect the spent fuel pool, and ~~verification of~~verify current qualifications of operators and support staff needed to implement the procedures. Generation has been addressing additional actions requested by INPO for improving and maintaining core and spent fuel pool cooling during an extended loss of power for at least 24 hours.

In April 2011, the NRC named six senior managers and staff to its task force for examining the agency’s regulatory requirements, programs, processes, and implementation in light of information from the Fukushima Daiichi site in Japan, following the March 11 earthquake and tsunami (Task Force). On July 12, 2011, the Task Force issued a report of its review of the accident, including recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The Task Force’s report did not recommend any changes to the existing nuclear licensing process in the United States or changes in the storage of spent nuclear fuel within the plant’s spent nuclear fuel pools. During the fourth quarter of 2011, the NRC staff issued its recommendations for prioritizing and implementing the Task Force recommendations and an implementation schedule which was approved by the NRC subject to a number of conditions. The NRC staff confirmed the Task Force’s conclusions that none of the findings arising from the Task Force review presented an imminent risk to public health and safety.

In March 2012, the NRC authorized its staff to issue three immediately effective orders to commercial reactor licensees operating in the United States for compliance no later than December 31, 2016. In summary, the orders require licensees: (1) to provide sufficient onsite portable equipment and resources to maintain or restore cooling capabilities for the containment, core, and spent fuel pool until offsite equipment is available and have

offsite equipment and resources available to sustain cooling functions indefinitely; (2) to improve the venting systems with boiling water reactor Mark I or Mark II containments (or for the Mark II plants, install new systems) that help prevent or mitigate core damage in the event of a serious accident by making the systems accessible and operable in the event of a prolonged station blackout and inadequate cooling; and (3) to install instrumentation to provide a reliable indication of water level in the spent fuel pool.

Additionally, the NRC has issued a detailed information request to every operating commercial nuclear power plant in the United States. The information requested requires: (1) use of the current NRC guidance to reevaluate current seismic and flood risk hazards against the design basis and provide a plan of actions to address vulnerabilities, including risks exceeding the design basis; (2) performance of walk downs to ensure the ability to respond to seismic and external flooding events and provide a corrective action plan to the NRC to address

deficiencies; and (3) assessment of the means to provide power for communications equipment during a severe natural event and identify staffing required to implement the emergency plan for an event affecting all units with an extended loss of alternating current power and impeded access to the site.

~~The NRC staff~~Generation has ~~scheduled a number of meetings to obtain stakeholder input on implementation guidance for the orders and information requests. Generation is assessing~~assessed the impacts of the orders and information requests and will continue monitoring the additional recommendations under review by the ~~Staff,~~staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance is not anticipated to be significant to Generation’s financial position, results of operations, or cash flows ~~over~~through the ~~next five years (required~~required implementation deadline of December 31, ~~2016).~~2016. However, until the specific requirements and guidance for each ~~order, request for information, and~~ recommendation are established after obtaining stakeholder input, Generation is unable to determine with specificity the impact the recommendations may have on its nuclear units. Additionally, Generation’s current assessments are specific to the Tier 1 recommendations ~~and information requests~~ as the NRC has not taken specific action with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See ITEM 1A. RISK FACTORS of the Exelon 2011 Form 10-K for further discussion of the risk factors.

~~Generation’s plan for increasing the output through uprates of its nuclear generating stations has not changed as a result of the situation in Japan. However,~~ Generation will continue to monitor NRC directives and guidance that may impact the uprates and, as it has in the past, evaluate each project at the appropriate time and cancel or defer any uprate project that is not considered economical, whether due to energy prices, potential increased regulation, or other factors.

Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the wholesale and retail 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 power plants can obtain for their output, (2) the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, (3) the impacts on energy demand of factors, such as weather, economic conditions and implementation of energy efficiency and demand response programs, and (4) regulatory and legislative actions, such as the U.S. EPA’s CSAPR and the MATS. SeeEnvironmental Matters section below for further detail on CSAPR and the MATS.

The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues.

The market price for electricity is also affected by changes in the demand for electricity. Poor economic conditions, milder than normal weather, unexpected or unusual weather patterns and the growth of energy efficiency and demand response programs can depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on market prices for electricity and/or capacity. The continued sluggish economy in the United States has led to a decline in demand for electricity. ComEd and BGE are projecting load demand to remain essentially flat in 2012 compared to 2011, while PECO is projecting a decline of 2.0% in 2012 compared to 2011 as a result of the above drivers in addition to reduced oil refinery load in its service territory.

Since the third quarter of 2011, forward natural gas prices for 2013 and 2014 have declined significantly; reflecting an increase in supply due to strong natural gas production (due to shale gas development) and significantly warmer than normal weather, as well as generally lowered expectations for gas demand and economic growth rates. ~~Wholesale~~The continued sluggish economy in the United

States has also led to a decline in demand for electricity. ComEd is projecting load volumes to remain essentially flat in 2012 compared to 2011, while PECO and BG&E are projecting a decline of 2.4% and 2.5%, respectively, in 2012 compared to 2011. The projected declines at PECO and BG&E are a result of energy efficiency initiatives and weak economic conditions in their service territories, in addition to reduced refinery load at PECO.

If recent power ~~prices have likewise decreased in response in part~~price volatility and demand trends continue, they could adversely affect the Registrants’ ability to fund other discretionary uses of cash such as growth projects or to pay dividends at current levels. In addition, the ~~lower gas prices,~~economics may no longer support the continued operation of certain generating facilities, which could adversely affect Generation’s results of operations through increased depreciation rates, impairment charges and ~~to the late December 2011 judicial stay of the U.S. EPA’s CSAPR and various other market factors.~~accelerated future decommissioning costs.

Exelon also has exposure to worldwide financial markets. The ongoing European debt crisis has contributed to the instability in global credit markets. Further disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of ~~June~~September 30, 2012, approximately ~~40%~~30%, or ~~$4.3~~$3.1 billion, of the Registrants’ ~~available credit facilities~~aggregate total commitments were with European banks. The credit facilities include ~~$10.7~~$9.8 billion in aggregate total commitments of which ~~$8.0~~$7.9 billion was available as of ~~June~~September 30, 2012. There were no borrowings under the Registrants’ credit facilities as of ~~June~~September 30, 2012. See Note 9 of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.

Exelon routinely reviews its hedging policy, operating and capital costs, capital spending plans, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades. Based on the results of these assessments, Exelon management believes it is able to respond to changing market conditions in a manner that ensures reliable and safe service for Exelon’s customers and sufficient liquidity to operate Exelon’s businesses.

Hedging ~~Strategy~~Strategy.. Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2012 and 2013. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of ~~June~~September 30, 2012, the percentage of expected generation hedged was ~~99%-102%~~98%-101%, ~~79%-82%~~87%-90%, 55%-58%, and ~~46%-49%~~20%-23% for 2012, 2013, 2014 and ~~2014,~~2015, 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, excluding owned generation to be retired or sold in 2012. Equivalent sales represent all hedging products, which include other derivatives and certain non-derivative contracts including sales to ComEd, PECO and BGE to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.

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 ~~56%~~57% of Generation’s uranium concentrate

requirements from ~~2011~~2012 through ~~2015~~2016 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. ComEd, PECO and BGE mitigate exposure as a result of the regulatory mechanisms that allow them to recover procurement costs from retail customers.

Nuclear Uprate ~~Program~~Program.. In 2008, Generation ~~has~~ announced a series of planned power uprates across its nuclear fleet that, if and when completed, would result in between ~~1,175~~1,125 and ~~1,300~~1,200 MWs at an overnight cost of approximately ~~$3.5~~$3.4 billion in ~~2012~~2013 dollars, of which approximately ~~$900~~$950 million has been spent through ~~June~~September 30, 2012. Overnight costs do not include financing costs or cost escalation. 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.

The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the plan in light of changing market conditions. The amount of expenditures to implement the plan will be determined on a project-by-project basis in accordance with Exelon’s normal project evaluation standards and ultimately will depend on economic and policy developments and projected sources and uses of funds. Based on recent reviews, the nuclear uprate implementation plan was adjusted during the second and third quarters of 2012, primarily as a result of market conditions, resulting in the deferral or cancellation of certain projects. The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may further affect the timing and amount of the power increases associated with the power uprate initiative.

Uprate projects, representing approximately 75% of the planned uprate MWs, are either complete or underway at the Limerick ~~Three Mile Island (TMI)~~ and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remaining uprate MWs will come from an additional projects across Generation’s nuclear fleet beginning in 2012 and ending in 2018. At 1,300 nuclear-generated MWs, the uprates would displace 6 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The 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 projected sources and uses of funds, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards. A review of the LaSalle Extended Power Uprate was performed in the second quarter and the completion of the project was deferred by two years, primarily as a result of market conditions. The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may affect the timing and amount of the power increases associated with theextended power uprate ~~initiative. Through June~~project at Limerick currently scheduled to begin in 2017. All projects that are undertaken are expected to be completed by the end of 2021. From the program announcement through September 30, 2012, Generation has added 250 MWs of nuclear generation through its uprate program, with another 8215 MWs scheduled to be added during the remainder of 2012.

Generation Renewable ~~Development~~Development.. Generation ~~plans to construct~~is constructing multiple wind facilities in 2012, resulting in approximately 400 MWs of additional renewable generation. Total costs for the facilities are expected to be approximately ~~$715~~$710 million. Total costs incurred through ~~June~~September 30, 2012 were ~~approximately $400~~$555 million. Upon completion of these wind facilities, Generation will have approximately 1,300 MW of wind capacity within its portfolio of generating assets.

Generation is currently constructing a solar PV facility in Los Angeles County, California. The facility is expected to become operational during the first quarter of 2013. Upon completion, the facility will add 230 MWs to Generation’s renewable generation fleet. Total costs for the facility are expected to be

approximately $1.4 billion. Total costs incurred through ~~June~~September 30, 2012 were ~~approximately $250~~$512 million. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

New Nuclear Site Development. On Aug. 28, 2012, Exelon halted efforts to gain initial federal regulatory approvals for new nuclear construction in Victoria County, Texas. The company notified the Nuclear Regulatory Commission that it has withdrawn its Early Site Permit application for an 11,500-acre tract southeast of Victoria. The action is in response to low natural gas prices and economic and market conditions that have made

construction of new merchant nuclear power plants in competitive markets uneconomical now and for the foreseeable future. Exelon originally submitted an application for a combined construction and operating license for the Victoria County site in 2008, but never made a decision to build a nuclear plant there. In 2010, the company applied for an Early Site Permit, a change in licensing strategy that allowed Exelon to continue with some aspects of site evaluation and regulatory approvals while deferring a construction decision for up to 20 years. The withdrawal of the license brings an end to all project activity.

Utility ~~Infrastructure~~Infrastructure.. During the fourth quarter of 2011, EIMA was enacted in Illinois, which provides for a cost recovery structure under which ComEd plans to invest an additional $2.6 billion over a ten-year period, beginning in 2012, to modernize Illinois’ electric utility infrastructure and for greater certainty related to the recovery of costs by a utility through a pre-established distribution formula rate tariff.

In 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan, representing an investment of up to a total of $650 million, including its $200 million SGIG, on its smart grid and smart meter infrastructure.

In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million electric and gas smart meters at an expected total cost of approximately $480 million, including its $200 million SGIG for smart grid and other related initiatives.

See theRegulatory and Legislative Matters section below and Note 4 of the Combined Notes to Consolidated Financial Statements for additional information on the utility infrastructure projects.

Credit Facilities. Exelon, Generation, ComEd, PECO and BGE have unsecured syndicated revolving ~~and bilateral~~ credit facilities with aggregate bank commitments of ~~$2.9~~$2.0 billion, ~~$5.6~~$5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. ~~Their syndicated revolving~~Generation has a bilateral credit ~~facilities expire between October 2013 and March 2016. The bilateral facilities at Exelon and Generation have expirations that range from September 2013 through March 2016.~~facility with aggregate maximum availability of $0.3 billion.

On March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new unsecured facility with aggregate bank commitments of $1.0 billion. The new facility expires in March 2017, unless extended in accordance with the agreement.

On ~~July 18,~~August 10, 2012, Exelon Corporate, Generation, PECO and BGE ~~began the process of amending~~amended and ~~extending~~extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively. The amended credit facilities will reflect current market pricing and, maturities of five years from the close of the transactions. The transactions are expected to close and become effective inrespectively, through August 2012. The new covenants are expected to be substantially consistent with existing covenants. Generally, it is expected that costs incurred to amend and extend the facilities will be amortized over the newly extended lives of the facilities. The maturity of the $1.5 billion Constellation Credit Agreement will be amended to December 31, 2012. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facility terms.10, 2017.

Exelon expects lower liquidity requirements as a result of the merger due to the matching of load and generation.

Cost ~~Management~~Management.. 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 become more effective, efficient and innovative. Exelon is committed to maintaining a cost control focus and continues to analyze cost trends to identify future cost savings opportunities and implement more planning and performance-measurement tools to allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.

Exelon ~~2020~~2020.. In 2008, Exelon announced a comprehensive business and environmental strategic plan, which 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). ~~Exelon has incorporated Exelon 2020 into its overall business plans, and as~~As further legislation and regulation imposing requirements on emissions of air pollutants are promulgated, ~~its~~Exelon’s 2020 emissions reduction efforts will position Exelon to benefit from the long-term positive impact of the requirements on capacity and energy prices while minimizing the impact of costs of compliance on Exelon’s operations, cash flows or financial position.

Exelon supports the promulgation of environmental regulation by the U.S. EPA, including air, water and waste controls for electric generating units. See discussion below for further details. 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 their low emission generation portfolios, Generation and CENG will not be significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the Congress that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.

~~Air~~~~. Beginning with the CSAPR, the air requirements are being implemented through a series of increasingly stringent regulations relating to conventional air pollutants (e.g., NO~~_x~~, SO~~₂ and particulate matter) as well as HAPs (e.g., acid gases, mercury and other heavy metals). It is expected that the U.S. EPA will complete a review of NAAQS in the 2012 — 2013 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide and lead. This review will likely result in more stringent emissions limits on fossil-fuel fired electric generating stations. There is opposition among fossil fuel-fuel fired generation owners to the potential stringency and timing of these air regulations, and the House Commerce and Energy Committee and several of its subcommittees have held a number of hearings on these issues.

On July 7, 2011, the U.S. EPA published CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. On October 14, 2011 and February 7, 2012, the U.S. EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to CSAPR. On June 12, 2012, the U.S. EPA issued its final technical corrections and associated updates to state emission budgets, and generating unit emission allowance allocations.

Several entities challenged the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit, and requested a stay of the rule pending the Court’s consideration of the matter on the merits. Exelon received permission from the Court to intervene in support of CSAPR and in opposition to the stay. On December 30, 2011, the Court granted a stay and directed the U.S. EPA to continue the administration of CAIR in the interim. The Court ordered an expedited case management schedule that resulted in oral argument on April 13, 2012. It is unknown when the Court will issue its decision on the merits. Exelon believes that CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the Clean Air Act. Upon preliminary review, it is expected that once implemented CSAPR will modestly increase power prices over the short term, which would result in a net benefit to Generation’s and CENG’s results of operations and cash flows.

On December 16, 2011, the U.S. EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the new source performance standards for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the MATS rule may need to upgrade existing controls or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon has petitioned the Court to intervene in support of the rule.

Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS by January 1, 2015. In addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation — Brandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for the merger, Exelon agreed to divest these generating stations. It is anticipated that these plants are well positioned to comply with CSAPR and MATS, since Maryland has adopted SO₂~~, NO~~_x~~, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.~~

The cumulative impact of these regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO₂ ~~and acid gases, and selective catalytic reduction technology for NO~~_x.

In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act, including permitting requirements under the PSD and Title V operating permit sections of the Clean Air Act for new and modified stationary sources that became effective on January 2, 2011. On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO₂ ~~emissions. Under the PSD 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.~~

Exelon supports comprehensive climate change legislation by the U.S Congress, 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 national GHG emissions. Several bills containing provisions for legislation of GHG emissions were introduced in Congress from January 2009 through January 2011, but none were passed by both houses of Congress.

~~Water~~. Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. Regulations adopted by the U.S. EPA in 2004 applicable to large electric generating stations were withdrawn in 2007 following a decision by the U.S. Second Circuit Court of Appeals that invalidated many of the rule’s significant provisions and remanded the rule to the U.S. EPA for further consideration and revision. On March 28, 2011, the U.S. EPA issued a proposed rule, and is required under a Settlement Agreement to issue a final rule by July 27, 2012. The proposed rule does not require closed cycle cooling (e.g., cooling towers) as the best technology available, and also provides some flexibility in the use of cost-benefit considerations and site-specific factors. The proposed rule affords the state permitting agency wide discretion to determine the best technology available, which, depending on the site characteristics, could include closed cycle cooling, advanced screen technology at the intake, or retention of the current technology. In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. On July 18, 2012, the U.S. EPA announced that it had agreed to extend the deadline to issue a final rule until June 27, 2013.

It is unknown at this time whether the final regulations or permit will require closed-cycle cooling at 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. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation.

~~Waste~~. Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion residuals (CCR) would be regulated for the first time under the RCRA. The U.S. EPA is considering several options, including classification of CCR either as a hazardous or non-hazardous waste under RCRA. 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. The Generation plants that would be affected by the proposed rules are Keystone and Conemaugh in Pennsylvania and Brandon Shores, H.A. Wagner, and C.P. Crane in Maryland. Keystone and Conemaugh each have on-site landfills that meet the requirements of Pennsylvania solid waste regulations for non-hazardous waste disposal. The Maryland facilities have exclusive use of a newly constructed landfill that meets the RCRA hazardous waste requirements. In connection with certain of the regulatory approvals required

for the merger with Constellation, Exelon agreed to divest the Maryland generating stations and the landfill is included in the sale. As a result, only the adoption of the hazardous waste standards would have an impact on Exelon’s Pennsylvania facilities, and the extent of that impact is unknown at this time. The U.S. EPA has not announced a target date for finalization of the CCR rules.

~~See Note 16 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.~~

EIMA provides a structure for substantial capital investment over a ten-year period to modernize Illinois’ electric utility infrastructure. EIMA allows the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC; and will provide greater certainty as to the recovery of those costs. ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make annual contributions of $4 million beginning in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates.

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June. On May 30, 2012, the ICC issued its final Order (Order) in that proceeding. The Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC’s determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in the annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd’s pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 periods and for the first three months of 2012 consistent with the terms of the Order. On June 5, 2012, ComEd filed its application for rehearing with the ICC. On June 22, 2012, the ICC granted expedited rehearing on ComEd’s pension asset recovery, the use of average or year-end rate base in determining ComEd’s reconciliation revenue requirement and the interest rate charged on over/under recovered costs. The expected

schedule for the rehearing allows for a decision by September 19, 2012. As a further result of the Order, on July 6, 2012, ComEd filed for rehearing of the AMI Deployment Plan to amend the timing and amount of the capital investment under that plan. On July 11, 2012, the ICC granted rehearing on ComEd’s AMI Deployment Plan. A final order on rehearing is due by December 7, 2012.

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred (the rates will take effect in January 2013). ComEd updated its 2011 reconciliation filing on June 12, 2012 to reflect the impacts of the Order discussed above. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of June 30, 2012 and December 31, 2011, ComEd recorded an estimated net regulatory asset of $26 million and $84 million, respectively, which represents the ICC’s approved distribution formula and associated rulings as of June 30, 2012 and ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred for the twelve months ended December 31, 2011 and for the six months ended June 30, 2012. The evidentiary hearing in ComEd’s 2011 reconciliation rate case is expected to begin on September 25, 2012, with a final order due by December 26, 2012.

~~Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd)~~. The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. 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 post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP). The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order in the remand proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal. ComEd has recognized for accounting purposes its best estimate of any refund obligation.

~~Advanced Metering Program Proceeding (Exelon and ComEd)~~. In October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of other costs from recovery under Rider AMP to recovery through base electric distribution rates. On March 19, 2012, the Court reversed Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court’s order on March 19, 2012, which would have an immaterial impact at ComEd and Exelon.

~~Financial Reform Legislation~~. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in the energy industry to hedge their risks. In April 2012, the CFTC issued its rule defining swap dealers and major swap participants. Exelon is continuing to evaluate the rule, and it has not yet determined whether it will be required to register all or a part of Exelon’s commercial business as a swap dealer or major swap participant. There are additional rulemakings that have not yet been issued, including the capital and margin rules, which will further define the scope of the regulations and

provide clarity as to the impact on the Registrants’ business, as well as to potential new opportunities. Depending on the final rules, the Registrants could be subject to significant new obligations.

The proposed regulations addressing collateral and capital requirements and exchange margin cash postings, when final, could require Generation to increase collateral requirements or the amount of exchange margin cash postings in lieu of letters of credit currently issued on over-the-counter contracts. Whether or not the new regulations apply directly to Generation, it estimates that it may be required to make up to $1 billion of additional collateral postings based upon market conditions as of June 30, 2012. The level of collateral required would depend on multiple factors, including but not limited to market conditions, derivative activity levels and Generation’s credit ratings. Generation has adequate credit facilities and flexibility in its hedging program to accommodate these legislative or market changes. In addition, the final regulations may impose substantial new and ongoing compliance and infrastructure requirements on us, which may amount to several million dollars per year. Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operations, cash flows or financial position.

~~New Electric Generation Legislation and Regulations~~. Various states have implemented or proposed policies to subsidize generation that would artificially depress wholesale energy and capacity prices. For example, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 700 MW combined cycle gas turbine in Waldorf, Maryland, with a projected commercial operation date of June 1, 2015. The CfD provides the utilities would pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from bidding the unit into the PJM markets. The utilities have filed written comments on the revised CfD that has been proposed by the MDPSC’s consultant and have provided further comments at a hearing on July 31, 2012. Similarly, in January 2011, New Jersey passed legislation that provides guaranteed cost recovery through a CfD for the development of up to 2,000 MWs of new base load or mid-merit generation, so long as it clears in PJM’s capacity market. Three generation developers were chosen for the New Jersey CfD, which were executed by the state’s utilities under protest. Similarly, in Illinois, legislation passed in the Senate and currently being considered in the House would require consumers to subsidize the development of an Integrated Gasification Combined Cycle plant by purchasing its electricity through 30 year power purchase agreements at prices significantly above market prices. All of these state efforts, if successful, could artificially depress wholesale capacity and/or energy prices. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position and could have a material effect on Exelon’s financial results of operations, financial position and cash flows.

Exelon has taken action against some of these anti-competitive policies through legal, legislative and regulatory challenges. Additionally, PJM’s Minimum Offer Price Rule (MOPR) was modified to preclude certain generators from artificially affecting capacity prices. See Note 4 of the Combined Notes to Consolidated Financial Statements for further details related to PJM’s MOPR.

~~Reliability and Quality of Service Standards (Exelon and BGE)~~~~. During its 2011 legislative session, the Maryland General Assembly passed legislation:~~

In May 2011, the Governor of Maryland signed this legislation into law, and the new service quality and reliability regulations became effective on May 28, 2012. These regulations could have a material impact on BGE’s financial results of operations, cash flows and financial position. BGE did seek recovery of these costs in the current base rate case filed on July 27, 2012.

~~2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE)~~. On July 27, 2012, BGE filed an application for increases of $151 million and $53 million to its electric and gas base rates, respectively with the MDPSC. The requested rate of return on equity in the application is 10.5%. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

RICE NESHAP. On June 7, 2012 the U.S. EPA issued a proposed rule under section 112 of the CAA to amend the NESHAP for stationary reciprocating internal combustion engines (RICE). The proposed RICE NESHAP resulted from the settlement of various legal challenges to 2010 RICE NESHAP. The proposed rule would allow stationary emergency diesel engines without emissions controls to operate for up to 100 hours per year for maintenance and emergency demand response programs, including a temporary allowance until April 17, 2017, of up to 50 hours per year for peak shaving and other nonemergency use. This represents a significant increase in the 15 hours of emergency demand response that is currently permitted under the 2010 RICE NESHAP. As a result of the proposed rule, additional megawatts of demand response may be bid into PJM, resulting in a negative impact on capacity prices. Exelon expects to file comments to the proposed rule that would support a more limited expansion of demand response hours and peak shaving and other nonemergency use, expiring in 2017.

Air. Beginning with the CSAPR, the air requirements are being 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). It is expected that the U.S. EPA will complete a review of NAAQS in the 2012 — 2014 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide and lead. This review will likely result in more stringent emissions limits on fossil-fuel fired electric generating stations. There is opposition among fossil fuel-fuel fired generation owners to the potential stringency and timing of these air regulations, and the House Commerce and Energy Committee and several of its subcommittees have held a number of hearings on these issues.

permission from the Court to intervene in support of CSAPR and in opposition to the stay. On December 30, 2011, the Court granted a stay and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA had exceeded its authority in certain material aspects with respect to CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. On October 5, 2012, the DOJ, on behalf of the U.S. EPA, filed a petition for a re-hearingen banc (i.e., before all the D.C. Circuit Court judges) of the panel’s decision. On the same date Exelon joined with other industry members in a petition for anen banc review. Due to the uncertainties of the on-going litigation, and the content and timing of a final CSAPR after remand, Exelon cannot predict the impact on power prices. Exelon continues to believe that the CSAPR is a valid exercise of the U.S. EPA’s authority and discretion under the Clean Air Act.

On December 16, 2011, the U.S. EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the new source performance standards for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the MATS rule may need to upgrade existing controls or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon has been granted permission by the Court to intervene in support of the rule. A decision by the Court is not expected until some time in 2013.

Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS by January 1, 2015. In addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation — Brandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for the merger, Exelon has entered into an agreement to sell these generating stations. The transaction, which is subject to approval by FERC and DOJ, is expected to close in the fourth quarter of 2012. It is anticipated that these plants are well positioned to comply with CSAPR and MATS, since Maryland has adopted SO2, NOx, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.

The cumulative impact of these regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO₂ and acid gases, and selective catalytic reduction technology for NO_x.

In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act, including permitting requirements under the PSD and Title V operating permit sections of the Clean Air Act for new and modified stationary sources that became effective on January 2, 2011. On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO2 emissions. Under the PSD 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.

Water. Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. Regulations adopted by the U.S. EPA in 2004 applicable to large electric generating stations were withdrawn in 2007 following a decision by the U.S. Second Circuit Court of Appeals that invalidated many of the rule’s significant provisions and remanded the rule to the U.S. EPA for further consideration and revision. On March 28, 2011, the U.S. EPA issued a proposed rule, and is required under a Settlement Agreement to issue a final rule by July 27, 2012. The proposed rule does not require closed cycle cooling (e.g., cooling towers) as the best technology available, and also provides some flexibility in the use of cost-benefit considerations and site-specific factors. The proposed rule affords the state permitting agency wide discretion to determine the best technology available, which, depending on the site characteristics, could include closed cycle cooling, advanced screen technology at the intake, or retention of the current technology. In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. On July 18, 2012, the U.S. EPA announced that it had agreed to extend the deadline to issue a final rule until June 27, 2013.

Waste. Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion residuals (CCR) would be regulated for the first time under the RCRA. The U.S. EPA is considering several options, including classification of CCR either as a hazardous or non-hazardous waste under RCRA. 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. The Generation plants that would be affected by the proposed rules are Keystone and Conemaugh in Pennsylvania and Brandon Shores, H.A. Wagner, and C.P. Crane in Maryland. Keystone and Conemaugh each have on-site landfills that meet the requirements of Pennsylvania solid waste regulations for non-hazardous waste disposal. The Maryland facilities have exclusive use of a newly constructed landfill that meets the RCRA hazardous waste requirements. In connection with certain of the regulatory approvals required for the merger with Constellation, Exelon agreed to divest the Maryland generating stations and the landfill is included in the sale. As a result, only the adoption of the hazardous waste standards would have an impact on Exelon’s Pennsylvania facilities, and the extent of that impact is unknown at this time. The U.S. EPA has not announced a target date for finalization of the CCR rules.

See Note 16 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

$4 million beginning in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates.

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June. On May 29, 2012, the ICC issued its final Order (May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC’s determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd’s pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 periods and for the first three months of 2012 consistent with the terms of the May Order.

On June 22, 2012, the ICC granted an expedited rehearing on the issues of ComEd’s pension asset recovery, the use of average or year-end rate base in determining ComEd’s reconciliation revenue requirement and the interest rate charged on over/under recovered costs. On October 3, 2012, the ICC issued its final order (Rehearing Order) in ComEd’s expedited rehearing. The Rehearing Order adopted ComEd’s position on the return on its pension asset, resulting in an increase in ComEd’s annual revenue requirement. In two other areas, the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in ComEd’s reconciliation revenue requirement; and amending its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed an appeal of the May Order and the Rehearing Order in court on October 4, 2012. While the ICC’s October 3, 2012, ruling to allow recovery on the pension asset as proposed by ComEd is important, this decision does not eliminate all of the revenue shortfall resulting from the numerous other problematic findings in the orders. The relevant findings are contrary to the provisions of the EIMA, and are the subject to ComEd’s appeals of the May Order and the Rehearing Order. These findings, in the aggregate, will result in a projected revenue deficit of about $100 million per year in 2014 and beyond.

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred (the rates will take effect in January 2013). ComEd updated its 2011 reconciliation filing on June 12, 2012 to reflect the impacts of the Order discussed above. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of September 30, 2012 and December 31, 2011, ComEd recorded an estimated net regulatory asset of $74 million and $84 million, respectively, which represents the ICC’s approved distribution formula and associated rulings as of September 30, 2012 and ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred for the twelve months ended December 31, 2011 and for the nine months ended September 30, 2012. The evidentiary hearing in ComEd’s 2011 reconciliation rate case was held on September 25, 2012, and a final order is due by December 26, 2012.

Advanced Metering Program Proceeding (Exelon and ComEd). In October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of other costs from recovery under Rider AMP to recovery through base electric distribution rates. On March 19, 2012, the Court reversed the ICC’s approval of Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. The Illinois Supreme Court denied the Petition on September 26, 2012, and returned the matter to the ICC to calculate a refund amount. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court’s order on March 19, 2012, which would have an immaterial impact at ComEd and Exelon.

Financial Reform Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in the energy industry to hedge their risks. In April 2012, the CFTC issued its rule defining swap dealers and major swap participants. Exelon has determined that it will conduct its commercial business in a manner that does not require registration as a swap dealer or major swap participant. Notwithstanding, there are additional rulemakings that have not yet been issued, including the capital and margin rules, which will further define the scope of the regulations and provide clarity as to the impact on the Registrants’ business, as well as to potential new opportunities. Depending on these final rules, the Registrants could be subject to significant new obligations.

The proposed regulations addressing collateral and capital requirements and exchange margin cash postings, when final, could require Generation to increase collateral requirements or cash postings in lieu of letters of credit currently issued to collateralize Swaps. Exelon had previously estimated that it could be required to make up to $1 billion of additional collateral postings to its bilateral credit lines. Given the swap dealer and the major swap participant definitions will not apply to Generation, the actual amount of collateral postings that will be required may be lower than Exelon’s previous expectations due to the following factors: (a) the majority of Generation’s physical wholesale portfolio does not meet the final CFTC Swap definition; (b) there will be minimal incremental costs associated with our positions that are currently cleared and subject to exchange margin; and (c) Generation will not be a swap dealer or major swap participant and proposed capital requirements applicable to these entities will not apply to Generation.

The actual level of collateral required will depend on many factors, including but not limited to market conditions, the outcome of final margin rules for Swaps, the extent of its trading activity in Swaps, and Generation’s credit ratings. Nonetheless, Generation has adequate credit facilities and flexibility in its hedging program to meet its anticipated collateral requirements estimated based on conservative assumptions.

In addition, the new regulations will impose new and ongoing compliance and infrastructure costs on Generation, which may amount to several million dollars per year.

Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operations, cash flows or financial position.

New Electric Generation Legislation and Regulations. Various states have implemented or proposed policies to subsidize generation that would artificially depress wholesale energy and capacity prices. For example, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 700 MW combined cycle gas turbine in Waldorf, Maryland, with a projected commercial operation date of June 1, 2015. The CfD provides the utilities would pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from bidding the unit into the PJM markets. Similarly, in January 2011, New Jersey passed legislation that provides guaranteed cost recovery through a CfD for the development of up to 2,000 MWs of new base load or mid-merit generation, so long as it clears in PJM’s capacity market. Three generation developers were chosen for the New Jersey CfD, which were executed by the state’s utilities under protest. Similarly, in Illinois, legislation passed in the Senate and currently being considered in the House would require consumers to subsidize the development of an Integrated Gasification Combined Cycle plant by purchasing its electricity through 30 year power purchase agreements at prices significantly above market prices. All of these state efforts, if successful, could artificially depress wholesale capacity and/or energy prices. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position and could have a material effect on Exelon’s financial results of operations, financial position and cash flows.

Reliability and Quality of Service Standards (Exelon and BGE). During its 2011 legislative session, the Maryland General Assembly passed legislation:

2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October, 22, 2012, BGE updated its application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

FERC Ameren Order (Exelon and ComEd). . In July 2012, FERC issued an order to Ameren Corporation indicating that Ameren had improperly included acquisition premiums/ goodwill in its transmission formula rate, particularly in its capital structure and in the application of AFUDC. FERC also directed Ameren to make refunds for the implied increase in rates in prior years. ~~ComEd expects~~ Ameren ~~will seek~~has filed for rehearing ~~and/or appeal~~regarding the July 2012 FERC order. ComEd believes that the FERC order authorizing its transmission formula rate is distinguishable from the circumstances that led to the July 2012 FERC order in the Ameren case. However, if ComEd were required to exclude acquisition premiums/ goodwill from its transmission formula rate, the impact could be material to ComEd’s results of operations and cash flows.

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in the Exelon’s, Generation’s, ComEd’s and PECO’s combined 2011 Form 10-K and Constellation’s and BGE’s combined 2011 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, purchase accounting, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies and revenue recognition. At ~~June~~September 30, 2012, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2011.


	Three Months Ended June 30,				Favorable (Unfavorable) Variance			Six Months Ended June 30,					Favorable (Unfavorable) Variance			Three Months Ended September 30,						Favorable (Unfavorable) Variance				Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2012(a)		2011		Favorable (Unfavorable) Variance			2012(a)			2011		Favorable (Unfavorable) Variance			2012(a)			2011						2012(a)				2011			Favorable (Unfavorable) Variance
Exelon	$	286	$	620	$	(334	)	$	486		$	1,288	$	(802	)	$	296		$	601		Favorable (Unfavorable) Variance	$	(305	)		$	782		$	1,889		$	(1,107	)
Generation		166		443		(277	)		334			938		(604	)		91			386			(295	)			425			1,325			(900	)
ComEd		42		114		(72	)		129			183		(54	)		90			112			(22	)			219			295			(76	)
PECO		79		82		(3	)		175			208		(33	)		122			104			18				297			311			(14	)
BGE		13		13		—			(20	)		91		(111	)		(4	)		(2	)		(2	)			(24	)		89			(113	)


	Three Months Ended June 30,						Favorable (Unfavorable) Variance				Six Months Ended June 30,							Favorable (Unfavorable) Variance				Three Months Ended September 30,							Favorable (Unfavorable) Variance				Nine Months Ended September 30,							Favorable (Unfavorable) Variance
	2012			2011						2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance
Operating revenues	$	3,753		$	2,455		Favorable (Unfavorable) Variance	$	1,298			$	6,492			$	5,098		$	1,394			$	4,017			$	2,821		$	1,196			$	10,509			$	7,919		$	2,590
Purchased power and fuel expense		1,852			841			(1,011	)			2,896				1,724			(1,172	)			2,122				1,071			(1,051	)			5,018				2,795			(2,223	)

Revenue net of purchased power and fuel(a)		1,901			1,614			287				3,596				3,374			222				1,895				1,750			145				5,491				5,124			367
Other operating expenses
Operating and maintenance		1,166			763			(403	)			2,340				1,517			(823	)			1,415				790			(625	)			3,756				2,306			(1,450	)
Depreciation and amortization		204			138			(66	)			357				277			(80	)			207				139			(68	)			564				416			(148	)
Taxes other than income		90			66			(24	)			164				132			(32	)			109				67			(42	)			272				199			(73	)

Total other operating expenses		1,460			967			(493	)			2,861				1,926			(935	)			1,731				996			(735	)			4,592				2,921			(1,671	)

Equity in loss of unconsolidated affiliates		(57	)		—			(57	)			(79	)			—			(79	)
Equity in earnings (losses) of unconsolidated affiliates																							10				—			10				(69	)			—			(69	)
Operating income		384			647			(263	)			656				1,448			(792	)			174				754			(580	)			830				2,203			(1,373	)

Other income and (deductions)
Interest expense		(85	)		(45	)		(40	)			(138	)			(91	)		(47	)			(85	)			(37	)		(48	)			(223	)			(128	)		(95	)
Equity in losses of investments		—			—			—				—				—			—
Other, net		(76	)		76			(152	)			103				152			(49	)			83				(164	)		247				185				(12	)		197

Total other income and (deductions)		(161	)		31			(192	)			(35	)			61			(96	)			(2	)			(201	)		199				(38	)			(140	)		102

Income before income taxes		223			678			(455	)			621				1,509			(888	)			172				553			(381	)			792				2,063			(1,271	)
Income taxes		58			235			177				289				571			282				85				167			82				373				738			365

Net income		165			443			(278	)			332				938			(606	)			87				386			(299	)			419				1,325			(906	)
Net income (loss) attributable to noncontrolling interests		(1	)		—			1				(2	)			—			2
Net loss attributable to noncontrolling interests																							(4	)			—			4				(6	)			—			6

Net income on common stock	$	166		$	443		$	(277	)		$	334			$	938		$	(604	)		$	91			$	386		$	(295	)		$	425			$	1,325		$	(900	)

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. Generation’s net income decreased compared to the same period in 2011 due to the impairment of certain generating assets in 2012 and higher operating ~~expenses, unfavorable~~expenses; offset by favorable NDT fund performance and ~~losses on Generation’s interest in CENG; offset by~~ higher revenues, net of purchased power and fuel expense. The increase in operating expenses and revenues, net of purchased power and fuel expense was primarily due to the addition of Constellation in 2012. See Note 3 for additional information regarding the impairment of certain generating assets in 2012.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011~~2011.. Generation’s net income decreased compared to the same period in 2011 due to the impairment of certain generating assets in 2012, higher operating expenses and ~~losses on Generation’s interest in CENG;~~the amortization of acquired energy contracts with CENG recorded at fair value at the merger date; offset by higher revenues, net of purchased power and fuel ~~expense.~~expense and favorable NDT fund performance. The increase in operating expenses was primarily due to the addition of Constellation’s financial results in 2012, costs associated with a settlement with FERC in March 2012 and transaction costs and employee-related costs associated with the merger. The increase in revenues, net of purchased power and fuel expense was also primarily due to the addition of Constellation in 2012. See Note 3 for additional information regarding the impairment of certain generating assets in 2012.

Generation’s six reportable segments are based on the geographic location of its assets, and are largely representative of the footprints of an Independent System Operator (ISO) / Regional Transmission Operator (RTO) and/or North American Electric Reliability Corporation (NERC) region. Descriptions of each of Generation’s six reportable segments are as follows:

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, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements. The following business activities are not allocated to a region, and are reported under Other: retail and wholesale gas, natural gas exploration and production activities, proprietary trading, energy efficiency and demand response, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems. Further, the following activities are not allocated to a region, and are reported in Other: compensation under the reliability-must-run rate schedule; results of operations from the clean-coal assets held for sale; Brandon Shores, Wagner, and C.P. Crane; mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger; and other miscellaneous revenues.

For the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, Generation’s revenue net of purchased power and fuel expense by region were as follows:


	Three Months Ended June 30,												Three Months Ended September 30,						Variance			% Change
	2012(a)			2011			Variance			% Change			2012(a)			2011						% Change
Mid-Atlantic(b)	$	883		$	819		$	64			7.8	%	$	908		$	835		Variance	$	73			8.7	%
Midwest(c)		764			887			(123	)		(13.9	%)		729			852			(123	)		(14.4	%)
New England		60			2			58			n.m.			81			1			80			n.m.
New York		39			—			39			n.m.			13			—			13			n.m.
ERCOT		119			(14	)		133			n.m.			159			103			56			54.4	%
Other Regions(d)		34			3			31			n.m.			42			(4	)		46			n.m.

Total electric revenue net of purchased power and fuel expense	$	1,899		$	1,697		$	202			11.9	%	$	1,932		$	1,787		$	145			8.1	%
Proprietary Trading		15			16			(1	)		(6.3	%)		(1	)		2			(3	)		(150.0	%)
Mark-to-market gains (losses)		200			(124	)		324			n.m.			17			(91	)		108			(118.7	%)
Other(e)		(213	)		25			(238	)		n.m.			(53	)		52			(105	)		n.m.

Total revenue net of purchased power and fuel expense	$	1,901		$	1,614		$	287			17.8	%	$	1,895		$	1,750		$	145			8.3	%


	Six Months Ended June 30,
	2012(a)			2011			Variance			% Change
Mid-Atlantic(b)	$	1,653		$	1,732		$	(79	)		(4.6	%)
Midwest(c)		1,581			1,851			(270	)		(14.6	%)
New England		99			5			94			n.m.
New York		47			—			47			n.m.
ERCOT		153			(9	)		162			n.m.
Other Regions(d)		48			(5	)		53			n.m.

Total electric revenue net of purchased power and fuel expense	$	3,581		$	3,574		$	7			0.2	%
Proprietary Trading		11			22			(11	)		(50.0	%)
Mark-to-market gains (losses)		260			(272	)		532			(195.6	%)
Other(e)		(256	)		50			(306	)		n.m.

Total revenue net of purchased power and fuel expense	$	3,596		$	3,374		$	222			6.6	%



	Nine Months Ended September 30,
	2012(a)			2011			Variance			% Change
Mid-Atlantic(b)	$	2,561		$	2,567		$	(6	)		(0.2	%)
Midwest(c)		2,310			2,704			(394	)		(14.6	%)
New England		180			6			174			n.m.
New York		60			—			60			n.m.
ERCOT		312			94			218			n.m.
Other Regions(d)		90			(10	)		100			n.m.

Total electric revenue net of purchased power and fuel expense	$	5,513		$	5,361		$	152			2.8	%
Proprietary Trading		10			24			(14	)		(58.3	%)
Mark-to-market gains (losses)		276			(363	)		639			n.m.
Other(e)		(308	)		102			(410	)		n.m.

Total revenue net of purchased power and fuel expense	$	5,491		$	5,124		$	367			7.2	%


	Three Months Ended June 30,										Three Months Ended September 30,				Variance			% Change
Supply source (GWh)	2012(a)		2011		Variance			% Change			2012(a)		2011		Variance			% Change
Nuclear generation(b)
Mid-Atlantic		12,277		11,172		1,105			9.9	%		11,449		12,158		(709	)		(5.8	%)
Midwest		22,860		21,995		865			3.9	%		23,132		23,887		(755	)		(3.2	%)

Total Nuclear Generation		35,137		33,167		1,970			5.9	%		34,581		36,045		(1,464	)		(4.1	%)
Fossil and Renewables(b)
Mid-Atlantic(b)(d)		2,316		2,052		264			12.9	%		2,547		1,722		825			47.9	%
Midwest		228		163		65			39.9	%		171		88		83			94.3	%
New England		2,755		2		2,753			n.m			3,953		2		3,951			n.m
New York		—		—		—			0	%		—		—		—			n.m
ERCOT(e)		2,177		207		1,970			n.m			2,410		1,214		1,196			98.5	%
Other Regions(f)		1,923		431		1,492			n.m			1,813		249		1,564			n.m

Total Fossil and Renewables		9,399		2,855		6,544			229.2	%		10,894		3,275		7,619			n.m.
Purchased power
Mid-Atlantic(c)		7,111		707		6,404			n.m			6,811		702		6,109			n.m
Midwest		1,558		1,659		(101	)		(6.1	%)		3,035		1,756		1,279			72.8	%
New England		3,905		—		3,905			n.m			1,961		—		1,961			n.m
New York(c)		2,818		—		2,818			n.m			4,026		—		4,026			n.m
ERCOT(e)		6,686		1,834		4,852			n.m			7,741		2,928		4,813			n.m
Other Regions(f)		6,012		577		5,435			n.m			5,372		887		4,485			n.m

Total Purchased Power		28,090		4,777		23,313			n.m.			28,946		6,273		22,673			n.m.
Total supply/sales by region(g)
Mid-Atlantic(h)		21,704		13,931		7,773			55.8	%		20,807		14,582		6,225			42.7	%
Midwest(i)		24,646		23,817		829			3.5	%		26,338		25,731		607			2.4	%
New England		6,660		2		6,658			n.m			5,914		2		5,912			n.m
New York		2,818		—		2,818			n.m			4,026		—		4,026			n.m
ERCOT		8,863		2,041		6,822			n.m			10,151		4,142		6,009			145.1	%
Other Regions(f)		7,935		1,008		6,927			n.m			7,185		1,136		6,049			n.m
	��
Total supply/sales by region		72,626		40,799		31,827			78.0	%		74,421		45,593		28,828			63.2	%


	Six Months Ended June 30,										Nine Months Ended September 30,
Supply source (GWh)	2012(a)		2011		Variance			% Change			2012(a)		2011		Variance		% Change
Nuclear generation(b)
Mid-Atlantic		24,341		23,543		798			3.4	%		35,790		35,700		90		0.3	%
Midwest		46,058		44,816		1,242			2.8	%		69,190		68,704		486		0.7	%

Total Nuclear Generation		70,399		68,359		2,040			3.0	%		104,980		104,404		576		0.6	%
Fossil and Renewables(b)
Mid-Atlantic(b)(d)		4,107		4,214		(107	)		(2.5	%)		6,654		5,936		718		12.1	%
Midwest		500		320		180			56.3	%		671		408		263		64.5	%
New England		3,644		6		3,638			n.m.			7,597		8		7,589		n.m.
New York		—		—		—			0	%		—		—		—		n.m.
ERCOT(e)		3,017		358		2,659			n.m.			5,427		1,572		3,855		n.m.
Other Regions(f)		2,742		789		1,953			n.m.			4,555		1,037		3,518		n.m.

Total Fossil and Renewables		14,010		5,687		8,323			146.4	%		24,904		8,961		15,943		n.m.
Purchased power
Mid-Atlantic(c)		9,688		1,457		8,231			n.m.			16,498		2,159		14,339		n.m.
Midwest		4,110		3,071		1,039			33.8	%		7,145		4,827		2,318		48.0	%
New England		5,005		—		5,005			0	%		6,966		—		6,966		n.m.
New York(c)		3,753		—		3,753			0	%		7,779		—		7,779		n.m.
ERCOT(e)		9,518		3,459		6,059			175.2	%		17,259		6,387		10,872		n.m.
Other Regions(f)		7,781		1,134		6,647			n.m.			13,153		2,021		11,132		n.m.

Total Purchased Power		39,855		9,121		30,734			n.m.			68,800		15,394		53,406		n.m.
Total supply/sales by region(g)
Mid-Atlantic(h)		38,136		29,214		8,922			30.5	%		58,942		43,795		15,147		34.6	%
Midwest(i)		50,668		48,207		2,461			5.1	%		77,006		73,939		3,067		4.1	%
New England		8,649		6		8,643			n.m.			14,563		8		14,555		n.m.
New York		3,753		—		3,753			0	%		7,779		—		7,779		n.m.
ERCOT		12,535		3,817		8,718			n.m.			22,686		7,959		14,727		n.m.
Other Regions(f)		10,523		1,923		8,600			n.m.			17,708		3,058		14,650		n.m.

Total supply/sales by region		124,264		83,167		41,097			49.4	%		198,684		128,759		69,925		54.3	%

The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the three and ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the three and ~~six~~nine months ended ~~June~~September 30, 2011.


	Six Months Ended June 30,								Three Months Ended September 30,
$/MWh~~(a)~~	2012(a)		2011			% Change			2012(a)		2011			% Change
Mid-Atlantic(b)	$	43.35	$	59.29			(26.9	%)	$	43.64	$	57.26			(23.8	%)
Midwest(c)		31.20		38.40			(18.8	%)		27.68		33.15			(16.5	%)
New England		11.45		n.m.			n.m.			13.70		n.m.			n.m.
New York		12.52		n.m.			n.m.			3.23		n.m.			n.m.
ERCOT		12.21		(2.10	)		n.m.			15.66		24.85			(37.0	%)
Other Regions(d)		4.56		(2.60	)		n.m.			5.85		(4.85	)		n.m.
Electric revenue net of purchased power and fuel expense per MWh(e)(f)		28.82		42.97			(32.9	%)		25.96		39.19			(33.8	%)

									Nine Months Ended September 30,					% Change
$/MWh(a)									2012(a)		2011			% Change
Mid-Atlantic(b)									$	43.48	$	58.61			(25.8	%)
Midwest(c)										30.00		36.57			(18.0	%)
New England										12.22		n.m.			n.m.
New York										7.71		n.m.			n.m.
ERCOT										13.75		11.94			15.2	%
Other Regions(d)										5.08		(3.27	)		n.m.
Electric revenue net of purchased power and fuel expense per MWh(e)(f)										27.75		41.64			(33.4	%)

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of ~~$64~~$73 million was primarily due to the addition of Constellation in 2012 and higher capacity revenues, partially offset by lower realized power ~~prices, lower capacity revenues and increased nuclear fuel costs.~~prices.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011~~2011. . The decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic of ~~$79~~$6 million was primarily due to lower realized power prices, ~~lower~~partially offset by higher capacity revenues and ~~increased nuclear fuel costs, partially offset by~~ the addition of Constellation in 2012.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The decrease in revenue net of purchased power and fuel expense in the Midwest of $123 million was primarily due to lower capacity revenues and lower realized power prices, ~~and increased nuclear fuel costs. These decreases were~~ partially offset by decreased congestion ~~costs and favorable settlements on the ComEd swap.~~costs.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011~~2011. . The decrease in revenue net of purchased power and fuel expense in the Midwest of ~~$270~~$394 million was primarily due to lower ~~capacity revenues, lower~~ realized power prices and ~~increased nuclear fuel costs. These decreases were~~lower capacity revenues, partially offset by decreased congestion ~~costs and favorable settlements on the ComEd swap.~~costs.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The ~~$58~~$80 million increase in revenue net of purchased power and fuel expense in New England was as a result of the Constellation merger. Prior to the merger, New England was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011~~2011. . The ~~$94~~$174 million increase in revenue net of purchased power and fuel expense in New England was as a result of the Constellation merger. Prior to the merger, New England was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The ~~$39~~$13 million increase in revenue net of purchased power and fuel expense in New York was as a result of the Constellation merger. Prior to the merger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011. The ~~$47~~$60 million increase in revenue net of purchased power and fuel expense in New York was as a result of the Constellation merger. Prior to the merger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The ~~$133~~$56 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily as a result of the Constellation ~~merger. The~~merger, partially offset by a decrease in revenue net of purchased power and fuel expense in the legacy Generation ERCOT ~~portfolio was relatively flat period over period.~~due to extreme weather and favorable market conditions in August 2011.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011~~2011. . The ~~$162~~$218 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily as a result of the Constellation ~~merger. The~~merger, partially offset by a decrease in revenue net of purchased power and fuel expense in the legacy Generation ERCOT portfolio ~~was relatively flat period over period.~~primarily driven by the performance of our generating units during the extreme weather events that occurred in Texas in February and August 2011.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, ~~2011~~2011. . The ~~$31~~$46 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily as a result of the Constellation merger.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011. The ~~$53~~$100 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily as a result of the Constellation merger.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market gains on economic hedging activities were ~~$200~~$16 million for the three months ended ~~June~~September 30, 2012 compared to losses of ~~$124~~$91 million for the three months ended ~~June~~September 30, 2011. See Notes 7 and 8 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market gains on economic hedging activities were ~~$260~~$276 million for the ~~six~~nine months ended ~~June~~September 30, 2012 compared to losses of ~~$272~~$363 million for the ~~six~~nine months ended ~~June~~September 30, 2011. See Notes 7 and 8 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011. The ~~$238~~$104 million decrease in other revenue net of purchased power and fuel was primarily due to the amortization of the acquired energy contracts recorded at fair value at the merger date. This decrease was partially offset by results from retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities. In addition, other revenue net of purchased power and fuel includes the results of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. See Note 3 of the Combined Notes to Consolidated Financial Statements for information regarding contract intangibles and assets planned for divestiture as a result of the Constellation merger.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011. The ~~$306~~$410 million decrease in other revenue net of purchased power and fuel was primarily due to the amortization of the acquired energy contracts recorded at fair value at the merger date. This decrease was partially offset by compensation under the reliability-must-run rate schedule, results from retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities. In addition, other revenue net of purchased power and fuel includes the results of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger. See Note 3 of the Combined Notes to Consolidated Financial Statements for information regarding contract intangibles and assets planned for divestiture as a result of the Constellation merger.

The following table presents nuclear fleet operating data for the three and ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the same periods in ~~June~~September 30, 2011, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of

time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial

information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Nuclear fleet capacity factor(a)		93.4	%		89.6	%		93.5	%		92.2	%		90.7	%		95.8	%		92.6	%		93.4	%
Nuclear fleet production cost per MWh(a)	$	18.48		$	19.41		$	19.27		$	19.06		$	19.04		$	17.35		$	19.19		$	18.47

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011.The nuclear fleet capacity factor ~~increased~~decreased primarily due to ~~fewer~~more non-refueling and refueling outage days, excluding Salem outages, during the three months ended ~~June~~September 30, 2012 compared to the same period in 2011. For the three months ended ~~June~~September 30, 2012 and 2011, non-refueling outage days totaled 40 and 3, respectively. During the same periods, refueling outage days totaled 5143 and ~~103,~~33, respectively. ~~The decrease in refueling outage days was primarily due to the timing of refueling outage activities performed in 2012 compared to 2011. Higher~~Lower number of net MWhs generated, ~~partially offset by~~ higher nuclear fuel costs and higher plant operating and maintenance expense resulted in a ~~lower~~higher production cost per MWh for the three months ended ~~June~~September 30, 2012 as compared to the same period in 2011.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011.The nuclear fleet capacity factor ~~increased~~decreased primarily due to more non-refueling outage days, partially offset by fewer refueling outage days, excluding Salem outages, during the ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011. For the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, non-refueling outage days totaled 72 and 41, respectively. During the same periods, refueling outage days totaled ~~118~~161 and ~~147,~~180, respectively. The decrease in refueling outage days was primarily due to the timing of refueling outage activities performed in 2012 compared to 2011. Higher nuclear fuel costs and higher plant operating and maintenance expense ~~partially offset by a higher number of net MWhs generated~~ resulted in higher production cost per MWh for the ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the same period in 2011.

The changes in operating and maintenance expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)			Increase (Decrease)			Increase (Decrease)			Increase (Decrease)
Labor, other benefits, contracting and materials	$	242		$	294		$	239		$	533
FERC settlement(a)		—			195
Impairment of certain generating assets(a)								278			278
FERC settlement(b)								—			195
Constellation merger and integration costs		40			112			20			132
Corporate allocations(b)		79			102
Corporate allocations(c)								60			168
Pension and non-pension postretirement benefits expense		39			54			43			97
Maryland commitments(c)		—			35
Bodily injury costs(d)		19			19
Maryland commitments(d)								—			35
Nuclear refueling outage costs, including the co-owned Salem plant(e)		(65	)		(51	)		3			(48	)
Other		49			63			(18	)		60

Increase in operating and maintenance expense	$	403		$	823		$	625		$	1,450

~~(b)~~(c)

Reflects the impact of an increased share of corporate allocated costs due to the merger.

~~(c)~~(d)

Reflects costs incurred as part of the Maryland order approving the merger transaction.

~~(d)~~

Reflects increase in asbestos-related bodily injury reserve recorded in the second quarter of 2012. See Note — 16 of the Combined Notes to Consolidated Financial Statements for additional information.

(e)	Reflects the impact of decreased planned refueling outage days induring the nine months ended September 30, 2012.

The increase in depreciation and amortization for the three and ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the three and ~~six~~nine months ended ~~June~~September 30, 2011 was primarily due to higher plant balances resulting from the addition of Constellation’s plant balances. The increase in depreciation and amortization expense was also due capital additions and upgrades to legacy facilities.

The increase in taxes other than income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the three and ~~six~~nine months ended ~~June~~September 30, 2011 was primarily due to the addition of Constellation’s financial results in 2012.

Equity in ~~losses~~earnings (losses) of unconsolidated affiliates for the three and ~~six~~nine months ended ~~June~~September 30, 2012 primarily reflected the net income generated from Exelon’s equity investment in CENG, the addition of the amortization of acquired energy contracts with CENG recorded at fair value at the merger date and the amortization of the basis difference of Generation’s ownership interest in CENG in connection with the Merger.

The increase in interest expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 as compared to the three and ~~six~~nine months ended ~~June~~September 30, 2011 was primarily due to the increase in long-term debt as a result of the merger. The increase in interest expense was also due to debt issued in 2012. See Note 9 of the Combined Notes to Consolidated Financial Statements for additional information.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011.Other, net primarily reflects the change in the net unrealized gains (losses) related to the NDT funds of the Non-Regulatory Agreement Units as described in the table below. Other, net also reflects ~~$12~~$48 million of ~~expense~~income in 2012 compared to ~~$19~~$71 million of ~~income~~expense in 2011 related to the contractual elimination of income tax ~~benefit~~expense in 2012 and income tax ~~expense~~benefit in 2011 associated with the NDT funds of the Regulatory Agreement ~~Units, $42~~Units; $43 million of credit facility termination fees recorded in 2012 and a $36 million bargain purchase gain associated with the ~~impact~~August 2011 acquisition of ~~$32 million one-time interest income from the NDT fund special transfer tax deduction recognized in 2011.~~Wolf Hollow.

~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011.Other, net primarily reflects the change in the net unrealized gains (losses) related to the NDT funds of the Non-Regulatory Agreement Units as described in the table below. Other, net also reflects ~~$52 million and $46~~$100 million of income in 2012 and $25 million of expense in 2011, ~~respectively,~~ related to the contractual elimination of income tax expense in 2012 and income tax benefit in 2011 associated with the NDT funds of the Regulatory Agreement ~~Units, $42~~Units; $85 million of credit facility termination fees recorded in 2012, a $36 million bargain purchase gain associated with the August 2011 acquisition of Wolf Hollow and the impact of a $32 million one-time interest income from the NDT fund special transfer tax deduction recognized in the second quarter of 2011.

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 ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011			2012		2011			2012		2011
Net unrealized gains (losses) on decommissioning trust funds	$	(35	)	$	11	$	30	$	54		$	71	$	(141	)	$	101	$	(88	)
Net realized gains (losses) on sale of decommissioning trust funds	$	3		$	—	$	40	$	(2	)	$	1	$	(1	)	$	41	$	(3	)

The effective income tax rate was ~~26.0%~~49.4% and ~~46.5%~~47.1% for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, compared to ~~34.7%~~30.2% and ~~37.8%~~35.8% for the same periods during 2011. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.


	Three Months Ended June 30,						Favorable (Unfavorable) Variance				Six Months Ended June 30,							Favorable (Unfavorable) Variance				Three Months Ended September 30,							Favorable (Unfavorable) Variance				Nine Months Ended September 30,							Favorable (Unfavorable) Variance
	2012			2011						2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance
Operating revenues	$	1,281		$	1,444		Favorable (Unfavorable) Variance	$	(163	)		$	2,670			$	2,910		$	(240	)		$	1,484			$	1,784		$	(300	)		$	4,154			$	4,694		$	(540	)
Purchased power expense		587			716			129				1,208				1,505			297				678				932			254				1,886				2,436			550

Revenue net of purchased power expense(a)		694			728			(34	)			1,462				1,405			57				806				852			(46	)			2,268				2,258			10

Other operating expenses
Operating and maintenance		331			268			(63	)			650				534			(116	)			350				396			46				1,000				930			(70	)
Depreciation and amortization		152			136			(16	)			300				270			(30	)			157				135			(22	)			458				405			(53	)
Taxes other than income		69			70			1				144				147			3				81				78			(3	)			224				226			2

Total other operating expenses		552			474			(78	)			1,094				951			(143	)			588				609			21				1,682				1,561			(121	)

Operating income		142			254			(112	)			368				454			(86	)			218				243			(25	)			586				697			(111	)

Other income and (deductions)
Interest expense, net		(74	)		(86	)		12				(156	)			(172	)		16				(74	)			(86	)		12				(230	)			(257	)		27
Other, net		3			4			(1	)			7				8			(1	)			5				16			(11	)			12				24			(12	)

Total other income and (deductions)		(71	)		(82	)		11				(149	)			(164	)		15				(69	)			(70	)		1				(218	)			(233	)		15

Income before income taxes		71			172			(101	)			219				290			(71	)			149				173			(24	)			368				464			(96	)
Income taxes		29			58			29				90				107			17				59				61			2				149				169			20

Net income	$	42		$	114		$	(72	)		$	129			$	183		$	(54	)		$	90			$	112		$	(22	)		$	219			$	295		$	(76	)

Three Months Ended ~~June~~September 30, 2012, Compared to Three Months Ended ~~June~~September 30, 2011.ComEd’s net income for the three months ended ~~June~~September 30, 2012, was lower than the same period in 2011 primarily due to ~~a reduction in revenue recorded as a~~the result of the May ~~30,~~29, 2012, final Order issued by the ICC in ComEd’s 2011 formula rate proceeding under EIMA. ~~Contributing to~~Offsetting the ~~decrease in net income were one-time net benefits recognized pursuant to~~impacts of the ~~May 2011~~ ICC Order, ~~in ComEd’s 2010 Rate Case and higher~~ComEd experienced reduced operating and maintenance expenses in ~~2012.~~2012 net of increased depreciation and amortization. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

~~Six~~Nine Months Ended ~~June~~September 30, 2012, Compared to ~~Six~~Nine Months Ended ~~June~~September 30, ~~2011.~~2011. ComEd’s net income for the ~~six~~nine months ended ~~June~~September 30, 2012, was lower than the same period in 2011 primarily due to higher operating and maintenance costs consisting of higher contracting costs and the impact of the one-time net benefits recognized pursuant to the May 2011 ICC Order in ComEd’s 2010 Rate Case. Also contributing to the decrease in net income were higher depreciation and amortization expenses resulting from an increase in capital additions.

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 4 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process.

Electric revenues and purchased power expense are 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 energy and generation services. The number of retail customers purchasing electricity from competitive electric generation suppliers was ~~668,209~~1,453,061 and ~~133,464~~249,714 at ~~June~~September 30, 2012, and 2011, respectively, representing ~~17%~~38% and 3%7% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented ~~62%~~64% and ~~61%~~62% of ComEd’s retail kWh sales for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, as compared to ~~56%~~53% and ~~55%~~54% for the three and ~~six~~nine months ended ~~June~~September 30, 2011, respectively. On March 20, 2012, 169 Illinois municipalities approved referendums regarding electric supply aggregation. This approval will allow municipal officials to begin the process to identify alternative electric generation suppliers. As contracts with new generation suppliers take effect, ComEd expects the percentage of retail deliveries purchased from competitive electric generation suppliers to continue to increase. The City of Chicago and other municipalities are also considering similar referenda.

The changes in ComEd’s electric revenue net of purchased power expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012, compared to the same periods in 2011 consisted of the following:

Revenues related to regulatory required programs are the recoveries from customers for costs of various legislative and/or regulatory programs on a full and current basis through approved regulated rates. Programs include ComEd’s uncollectible accounts tariff, energy efficiency and demand response and purchased power administrative costs. An equal and offsetting amount has been reflected in operating and maintenance expense during the periods presented. Refer to the operating and maintenance expense discussion below for additional information on included programs.

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. In addition to experiencing higher than normal temperatures in June 2012, Illinois experienced the warmest January through May period on record in 2012. The favorable weather conditions in the second quarter resulted in an increase in revenues net of purchased power expense for the three months ended June 30, 2012. For the six months ended June 30, 2012, the increase in revenues net of purchased power expense for the second quarter of 2012 was offset by unfavorable weather conditions as a result of the warm weather in the first quarter of 2012.

The ICC issued an Order (Order) in the 2010 Rate Case approving an increase in ComEd’s annual revenue requirement. The order became effective June 1, 2011 resulting in higher revenues for the three and six months ended June 30, 2012 compared to the same periods in 2011. The increase due to the 2010 Rate Case was partially offset by lower rates effective June 20, 2012 resulting from the final Order issued in ComEd’s 2011 formula rate proceeding under EIMA. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

ComEd records revenues subject to refund based upon its best estimate of customer collections that may be required to be refunded. As a result of the September 30, 2010 Illinois Appellate Court (Court) decision in the 2007 Rate Case that ruled against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via Rider SMP, ComEd began recording revenue subject to refund prospectively through June 1, 2011, when the rates in the 2010 Rate Case became effective. During the three and six months ended June 30, 2012, ComEd did not record revenues subject to refund associated with any matters.

ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s most recent annual formula rate update, filed in May 2012, reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. Transmission revenues net of purchased power expense vary from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. ComEd set a record for the highest daily peak load of 23,753 MWs on July 20, 2011, which was reflected in the determination of transmission revenues billed beginning January 1, 2012, and transmission rates that went into effect on June 1, 2012. See Note 4 of the Combined Notes to Consolidated Financial Statements.

Revenues net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, reflecting decreased average usage per residential customer for the ~~three and six~~nine months ended ~~June~~September 30, 2012. This decrease was slightly offset by an increase for the three months ended September 30, 2012, compared to the same periods in 2011.

~~Reversal~~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 ~~revenue subject to refund~~

~~Revenues~~electricity. Conversely, mild weather reduces demand. In spite of experiencing slightly lower than normal temperatures in September 2012, Illinois experienced the warmest January through August period on record in 2012. While the third quarter of 2012 saw an increase in weather related deliveries, the impact on revenues was offset by a decrease in pricing. For the nine months ended September 30, 2012, the increase in revenues net of purchased power ~~decreased~~expense for the second and third quarters of 2012 was offset by unfavorable weather conditions as a result of the ~~benefit recognized~~warm weather in the first quarter of 2012.

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 with cooling degree days generally having a more significant impact to ComEd, particularly during the second quarter of 2011 for reversing a reserve for revenues subject to refund. Subsequent to ICC approval, ComEd began billing customers for Cash Working Capital (CWC) through its energy procurement rider on June 1, 2010 reflecting the costs includedsummer months. The changes in heating and cooling degree days in ComEd’s ~~original request to amend~~service territory for the ~~tariff. Because~~three and nine months ended September 30, 2012 and 2011, consisted of the uncertainty regarding the methodology for determining CWC recovery, ComEd had been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarifies the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011.following:

EIMA provides a structure for establishing a performance-based formula rate tariff. EIMA provides for an annual reconciliation of the revenue requirement in effect under the formula rate to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. ComEd made its initial reconciliation filing on April 30, 2012, with respect to calendar year 2011 and the adjusted rates will take effect in January 2013 after

ICC review. On May ~~30,~~29, 2012, the ICC issued its final Order ~~(Order)~~(May Order) in the proceeding to establish ComEd’s formula rate under EIMA. The Order ~~reduces~~reduced the annual revenue requirement by $168 million by modifying or eliminating some of the elements of the formula. On October 3, 2012, the ICC issued an order on remand (Rehearing Order) overturning portions of the May Order. ComEd expects to record an increase in revenue of approximately $135 million in the fourth quarter of 2012 consistent with the terms of the Rehearing Order. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

ComEd records revenues subject to refund based upon its best estimate of customer collections that may be required to be refunded. During the three and nine months ended September 30, 2012, ComEd did not record revenues subject to refund associated with any matters. As a result of the September 30, 2010, Illinois Appellate Court (Court) decision in the 2007 Rate Case that ruled against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via Rider SMP, ComEd began recording revenue subject to refund prospectively. In addition, ComEd began recording revenue subject to refund on June 1, 2010, relating to the recovery of Cash Working Capital (CWC) through its energy procurement rider. Based on the 2010 Rate Case order as well as the proceeding on remand associated with the Court order, during the third quarter 2011 ComEd reduced its revenue subject to refund reserve. See Note 4 of the Combined Notes to Consolidated Financial Statements.

The ICC issued an order in the 2010 Rate Case approving an increase in ComEd’s annual revenue requirement. The order became effective June 1, 2011, resulting in higher revenues for the nine months ended September 30, 2012, compared to the same periods in 2011. The increase due to the 2010 Rate Case was partially offset by lower rates effective June 20, 2012, resulting from the final Order issued in ComEd’s 2011 formula rate proceeding under EIMA. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

Other revenues were higher during the three and ~~six~~nine months ended ~~June~~September 30, 2012, compared to the same periods in 2011. Other revenues, which can vary period to period, include rental revenues, revenues related to late payment charges, assistance provided to other utilities through mutual assistance programs and recoveries of environmental ~~remediation~~ costs associated with MGP sites.


	Three Months Ended June 30,				Increase (Decrease)				Six Months Ended June 30,							Increase (Decrease)				Three Months Ended September 30,							Increase (Decrease)				Nine Months Ended September 30,							Increase (Decrease)
	2012		2011					2012				2011				Increase (Decrease)			2012				2011				Increase (Decrease)			2012				2011				Increase (Decrease)
Operating and maintenance expense — baseline	$	276	$	236	Increase (Decrease)	$	40			$	537			$	462		$	75			$	332			$	353		$	(21	)		$	899			$	846		$	53
Operating and maintenance expense — regulatory required programs(a)		55		32		23				113				72			41				18				43			(25	)			101				84			17

Total operating and maintenance expense	$	331	$	268	$	63			$	650			$	534		$	116			$	350			$	396		$	(46	)		$	1,000			$	930		$	70

The changes in operating and maintenance expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011, consisted of the following:


	Three Months Ended June 30			Six Months Ended June 30			Three Months Ended September 30			Nine Months Ended September 30
	Increase (Decrease)			Increase (Decrease)			Increase (Decrease)			Increase (Decrease)
Baseline
Discrete impacts from 2010 Rate Case order(a)	$	32		$	32		$	—		$	32
Labor, other benefits, contracting and materials(b)		18			46			24			69
Pension and non-pension postretirement benefits expense		9			17			15			33
Incremental Storm Costs		(19	)		(21	)
Storm Related Costs(d)								(57	)		(78	)
Other		—			1			(3	)		(3	)

		40			75			(21	)		53
Regulatory required programs
Energy efficiency and demand response programs		31			48			(14	)		34
Purchased power administrative costs		3			3			(11	)		(7	)
Uncollectible accounts expense — provision		(1	)		3			—			(13	)
Uncollectible accounts expense — recovery, net(c)		(10	)		(13	)		—			3

		23			41			(25	)		17

Increase in operating and maintenance expense	$	63		$	116
Increase (Decrease) in operating and maintenance expense							$	(46	)	$	70

Depreciation and amortization expense increased during the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 primarily due to higher plant balances and amortization of the regulatory assets recorded in December 2011 and September 2012 to defer significant storm costs pursuant to EIMA.

Taxes other than income taxes decreased ~~during~~for the ~~three and six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 primarily due to decreased Illinois electricity distribution taxes. Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes, and payroll taxes.

Interest expense decreased during the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 due to favorable interest rates on outstanding long-term debt balances.

The effective income tax rate was ~~40.8%~~39.6% for the three months ended ~~June~~September 30, 2012 compared to ~~33.7%~~35.3% for the same period during 2011. The effective income tax rate was ~~41.1%~~40.5% for the ~~six~~nine months ended ~~June~~September 30, 2012 compared to ~~36.9%~~36.4% for the same period during 2011. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.


	Three Months Ended June 30,				% Change			Weather-Normal % Change
Retail Deliveries to customers (in GWhs)								Weather-Normal % Change			Three Months Ended September 30,			% Change			Weather-Normal % Change
Retail Deliveries to customers (in GWhs)	2012		2011		% Change	% Change			Weather-Normal % Change			2012	2011	% Change			Weather-Normal % Change
Retail Delivery and Sales(a)						% Change			Weather-Normal % Change
Residential		6,674		6,277		6.3	%		(2.7	)%		9,265	8,877		4.4	%		1.4	%
Small commercial & industrial		7,888		7,763		1.6	%		(1.8	)%		8,939	8,811		1.5	%		(0.1	)%
Large commercial & industrial		6,839		6,698		2.1	%		0.4	%		7,506	7,494		0.2	%		(0.8	)%
Public authorities & electric railroads		293		286		2.4	%		2.4	%		314	303		3.6	%		3.3	%

Total Retail		21,694		21,024		3.2	%		(1.3	)%		26,024	25,485		2.1	%		0.2	%


	Six Months Ended June 30,				% Change			Weather-Normal % Change
Retail Deliveries to customers (in GWhs)	2012		2011		% Change			Weather-Normal % Change
Retail Delivery and Sales(a)
Residential		13,080		13,231		(1.1	)%		(1.6	)%
Small commercial & industrial		15,804		15,837		(0.2	)%		(0.3	)%
Large commercial & industrial		13,542		13,517		0.2	%		0.6	%
Public authorities & electric railroads		617		616		0.2	%		3.3	%

Total Retail		43,043		43,201		(0.4	)%		(0.4	)%


	As of June 30,
Number of Electric Customers	2012		2011
Residential		3,456,312		3,447,194
Small commercial & industrial		365,474		364,902
Large commercial & industrial		1,990		2,007
Public authorities & electric railroads		4,793		4,914

Total		3,828,569		3,819,017

   Three Months Ended
June 30,    %
Change Six Months Ended
June 30,    % Change
Electric Revenue
   2012    2011    2012    2011
Retail Delivery and Sales(a)

Residential
   $ 720       $ 800       (10.0 )% $ 1,496       $ 1,634       (8.4 )%
Small commercial & industrial
   306    386    (20.7 )% 654    767    (14.7 )%
Large commercial & industrial
   94    95    (1.1 )% 194    186    4.3 %
Public authorities & electric railroads
   9    12    (25.0 )% 21    26    (19.2 )%









Total Retail
   1,129    1,293    (12.7 )% 2,365    2,613    (9.5 )%









Other Revenue(b)
   152    151    0.7 % 305    297    2.7 %









Total Electric Revenues
   $ 1,281       $ 1,444       (11.3 )% $ 2,670       $ 2,910       (8.2 )%


	As of September 30,
Number of Electric Customers	2012		2011
Residential		3,450,364		3,439,704
Small commercial & industrial		365,245		364,917
Large commercial & industrial		1,986		2,041
Public authorities & electric railroads		4,795		4,801

Total		3,822,390		3,811,463


	Three Months Ended June 30,						Favorable (Unfavorable) Variance				Six Months Ended June 30,							Favorable (Unfavorable) Variance				Three Months Ended September 30,							Favorable (Unfavorable) Variance				Nine Months Ended September 30,							Favorable (Unfavorable) Variance
	2012			2011						2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance
Operating revenues	$	715		$	842		Favorable (Unfavorable) Variance	$	(127	)		$	1,590			$	1,996		$	(406	)		$	806			$	946		$	(140	)		$	2,396			$	2,942		$	(546	)
Purchased power and fuel		296			408			112				707				1,042			335				326				464			138				1,033				1,506			473

Revenue net of purchased power and fuel(a)		419			434			(15	)			883				954			(71	)			480				482			(2	)			1,363				1,436			(73	)

Other operating expenses
Operating and maintenance		172			172			—				375				378			3				199				219			20				574				597			23
Depreciation and amortization		54			50			(4	)			107				98			(9	)			55				51			(4	)			161				150			(11	)
Taxes other than income		42			51			9				74				106			32				48				59			11				122				165			43

Total other operating expenses		268			273			5				556				582			26				302				329			27				857				912			55

Operating income		151			161			(10	)			327				372			(45	)			178				153			25				506				524			(18	)

Other income and (deductions)
Interest expense, net		(31	)		(34	)		3				(62	)			(68	)		6				(32	)			(34	)		2				(94	)			(102	)		8
Other, net		2			3			(1	)			5				8			(3	)			2				3			(1	)			6				11			(5	)

Total other income and (deductions)		(29	)		(31	)		2				(57	)			(60	)		3				(30	)			(31	)		1				(88	)			(91	)		3

Income before income taxes		122			130			(8	)			270				312			(42	)			148				122			26				418				433			(15	)
Income taxes		42			47			5				93				102			9				25				17			(8	)			118				119			1

Net income		80			83			(3	)			177				210			(33	)			123				105			18				300				314			(14	)
Preferred security dividends		1			1			—				2				2			—				1				1			—				3				3			—

Net income on common stock	$	79		$	82		$	(3	)		$	175			$	208		$	(33	)		$	122			$	104		$	18			$	297			$	311		$	(14	)

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.

Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011.The increase in net income was primarily due to decreased storm expenses in 2012. The increase was partially offset by lower electric revenue net of purchase power expense due to a decline in load.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011. The decrease in net income was primarily due to unfavorable weather and a decline in ~~load. The decrease in net income was partially offset by a decrease in labor, contracting and materials expense.~~

~~Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011.~~ ~~The decrease in net income was primarily due to unfavorable weather and a decline in~~electric load. The decrease in net income was partially offset by lower operating and maintenance expenses, taxes other than income and interest ~~expenses.~~expense. The decrease in operating and maintenance expense was primarily due to ~~decreased labor, other benefits, contracting, materials and~~lower storm ~~expenses.~~costs.

There are certain drivers to operating revenues that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs.

PECO’s electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenue net of purchased power and fuel expense.

Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customer’s choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and gas revenue net of purchased power and fuel expense. The number of retail customers purchasing electricity from a competitive electric generation supplier was ~~441,000~~464,800 and ~~306,900~~351,500 at ~~June~~September 30, 2012 and 2011, respectively. Retail deliveries purchased from competitive electric generation suppliers represented ~~67% and~~ 65% of PECO’s retail kWh sales for the three and ~~six~~nine months ended ~~June~~September 30, 2012, ~~respectively,~~ compared to ~~58%~~60% and ~~51%~~54% for the three and ~~six~~nine months ended ~~June~~September 30, 2011. The number of retail customers purchasing natural gas from a competitive natural gas supplier was ~~42,100~~48,600 and ~~14,000~~20,600 at ~~June~~September 30, 2012 and 2011, respectively. ~~Retail deliveries~~Deliveries purchased from competitive natural gas suppliers represented ~~58%~~69% and ~~42%~~47% of PECO’s ~~retail~~ mmcf sales for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, compared to ~~56%~~67% and ~~37%~~42% for the three and ~~six~~nine months ended ~~June~~September 30, 2011.

The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended ~~June~~September 30, 2012 compared to the same period in 2011 consisted of the following:


	Increase (Decrease)
	Electric			Gas		Total
Weather	$	4		$	—	$	4
Volume		(10	)		—		(10	)
Pricing		(8	)		—		(8	)
Regulatory required programs		18			—		18
Other		(6	)		—		(6	)

Total decrease	$	(2	)	$	—	$	(2	)

The changes in PECO’s operating revenues net of purchased power and fuel expense for the ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 consisted of the following:


	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	(31	)	$	(25	)	$	(56	)	$	(26	)	$	(25	)	$	(51	)
Volume		(13	)		1			(12	)		(23	)		1			(22	)
Pricing		7			3			10			(1	)		3			2
Regulatory required programs		3			—			3			22			—			22
Other		(15	)		(1	)		(16	)		(24	)		—			(24	)

Total decrease	$	(49	)	$	(22	)	$	(71	)	$	(52	)	$	(21	)	$	(73	)

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 six~~ months ended ~~June~~September 30, 2012 compared to the same ~~periods~~period in 2011, electric revenues net of purchased power were higher due to the impact of favorable weather conditions in PECO’s service territory during the third quarter of 2012.

During the nine months ended September 30, 2012 compared to the same period in 2011, operating revenues net of purchased power and fuel expense were lower due to the impact of unfavorable 2012 winter weather conditions in PECO’s service territory.


							% Change						2012			2011			Normal			% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal					From 2011						From Normal
Three Months Ended June 30,
Three Months Ended September 30,													2012
Heating Degree-Days		337		331		463		1.8	%		(27.2	)%		14		2011		18	Normal		35				(22.2	)%			(60.0	)%
Cooling Degree-Days		430		494		348		(13.0	)%		23.6	%		1,138			1,109			934			2.6	%			21.8	%

Six Months Ended June 30,
Nine Months Ended September 30,
Heating Degree-Days		2,251		2,837		2,939		(20.7	)%		(23.4	)%		2,265			2,855			2,974			(20.7	)%			(23.8	)%
Cooling Degree-Days		434		494		348		(12.1	)%		24.7	%		1,572			1,603			1,282			(1.9	)%			22.6	%

The decrease in electric operating revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 reflected the reduced oil refinery load in PECO’s service territory and the impact of energy efficiency initiatives and weak economic conditions on customer usage. The decrease for the ~~six~~nine months ended ~~June~~September 30, 2012 was partially offset by additional volumes due to the extra day from the leap year.

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011. The ~~increase~~decrease in ~~operating~~electric revenues net of purchased power ~~and fuel~~ expense as a result of pricing ~~for~~reflects the three and six months ended June 30, 2012 compared to the same periods in 2011 reflected higher overall effective rates due to decreased usage per customer across all customer classes. This was primarily offset by the

refund of the tax cash benefit resulting from the adoption of the safe harbor method of tax accounting for electric distribution property in 2011. The refund was reflected on customer bills as a credit beginning January 1, 2012. The accounting impact of the refund is completely offset by regulatory liability amortization recorded in income tax expense.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011. The increase in operating revenues net of purchased power and fuel expense as a result of pricing reflects higher overall effective rates due to decreased usage per customer across all customer classes. This was primarily offset by the refund of the tax cash benefit resulting from the adoption of the safe harbor method of tax accounting for electric distribution property in 2011. The refund was reflected on customer bills as a credit beginning January 1, 2012. The accounting impact of the refund is completely offset by regulatory liability amortization recorded in income tax expense.

This represents the change in operating revenues collected under approved riders to recover costs incurred for the smart meter and energy efficiency programs as well as the administrative costs for the ~~GSA.~~GSA and AEPS programs. The riders are designed to provide full and current cost recovery as well as a return. The offsetting costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.

The decrease in other electric revenues net of purchased power expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 reflected a decrease in GRT revenue as a result of lower supplied energy service and a reduction in the GRT rate. There is an equal and offsetting decrease in GRT expense included in taxes other than income.


	Three Months Ended June 30,				Increase (Decrease)			Six Months Ended June 30,				Increase (Decrease)			Three Months Ended September 30,				Increase (Decrease)				Nine Months Ended September 30,						Increase (Decrease)
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)			2012		2011					2012				2011			Increase (Decrease)
Operating and Maintenance Expense — Baseline	$	151	$	154	$	(3	)	$	335	$	340	$	(5	)	$	170	$	203	Increase (Decrease)	$	(33	)		$	506		$	543		$	(37	)
Operating and Maintenance Expense — Regulatory
Required Programs(a)		21		18		3			40		38		2			29		16		13				68			54			14

Total Operating and Maintenance Expense		172		172		—			375		378		(3	)		199		219		(20	)			574			597			(23	)

The changes in operating and maintenance expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)			Increase (Decrease)			Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	(14	)	$	(16	)	$	(10	)	$	(25	)
Storm-related costs		1			(8	)		(23	)		(31	)
Pension Benefits		3			6
Pension and non-pension postretirement benefits expense								3			8
Constellation merger and integration costs		4			11			2			12
Other		3			2			(5	)		(1	)

		(3	)		(5	)		(33	)		(37	)
Regulatory Required Programs
Smart Meter		2			6			1			7
Energy Efficiency		1			(2	)		12			10
GSA		—			(2	)		—			(2	)
AEPS								—			(1	)

		3			2			13			14

Decrease in operating and maintenance expense	$	—		$	(3	)	$	(20	)	$	(23	)

The decrease in taxes other than income for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 was primarily due to decreased GRT collections as a result of lower revenues and a reduction in the GRT rate. An equal and offsetting decrease in GRT has been reflected in operating revenues during the current periods. The decrease in taxes other than income for the ~~six~~nine months ended ~~June~~September 30, 2012 also reflects a sales and use tax reserve adjustment in the first quarter of 2012 resulting from the completion of the audit of tax years 2005 through 2010.

The decrease in interest expense ~~net~~ for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 was primarily due to lower interest expense as a result of the debt retirement in November 2011.

The decrease in Other, net for the ~~six~~three and nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 was due to decreased AFUDC-Equity. See Note 17 of the Combined Notes to the Consolidated Financial Statements for further details of the components of Other, net.

PECO’s effective income tax rate was ~~34.4%~~16.9% and ~~36.2%~~13.9% for the three months ended ~~June~~September 30, 2012 and 2011, respectively, and ~~34.4%~~28.2% and ~~32.7%~~27.5% for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, respectively. The effective income tax rate for the three and nine months ended September 30, 2012 reflect the impact of the tax benefit received from electing to change the method of accounting for gas distribution property for the 2011 tax year. Comparatively, the effective income tax rate for the three and nine months ended September 30, 2011 include the effect of electing the safe harbor method of tax accounting for electric transmission and distribution property for the 2010 tax year. See Note 10 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.


Retail Deliveries to customers (in GWhs)	Three Months Ended June 30,				% Change				Weather- Normal % Change				Six Months Ended June 30,								% Change				Weather- Normal % Change				Three Months Ended September 30,				% Change				Weather- Normal % Change				Nine Months Ended September 30,						% Change			Weather- Normal % Change
Retail Deliveries to customers (in GWhs)	2012		2011					2012						2011						2012								2011				2012				2011											% Change			Weather- Normal % Change
Retail Delivery and Sales(a)					% Change
Residential		2,929		3,075		(4.7	)%		Weather- Normal % Change		(0.7	)%			6,095				6,665		% Change			(8.6	Weather- Normal % Change	)%			(1.7	)%	4,059		% Change	4,085			Weather- Normal % Change		(0.6	)%			(3.6	)%		10,154			10,750			(5.5	)%	(2.4	)%
Small commercial & industrial		1,959		2,026		(3.3	)%			(1.9	)%			3,910				4,165				(6.1	)%			(3.5	)%			2,245		2,272		(1.2	)%			(1.6	)%			6,155			6,437			(4.4	)%		(2.8	)%
Large commercial & industrial		3,743		3,954		(5.3	)%			(4.9	)%			7,380				7,642				(3.4	)%			(3.4	)%			4,165		4,370		(4.7	)%			(4.8	)%			11,545			12,012			(3.9	)%		(3.9	)%
Public authorities & electric railroads		237		229		3.5	%			3.5	%			474				471				0.6	%			0.6	%			240		239		0.4	%			0.4	%			714			710			0.6	%		0.6	%

Total Electric Retail		8,868		9,284		(4.5	)%			(2.7	)%			17,859				18,943				(5.7	)%			(2.7	)%			10,709		10,966		(2.3	)%			(3.6	)%			28,568			29,909			(4.5	)%		(3.0	)%


	As of June 30,
Number of Electric Customers	2012		2011
Residential		1,417,346		1,412,692
Small commercial & industrial		148,837		148,116
Large commercial & industrial		3,107		3,127
Public authorities & electric railroads		9,680		9,661

Total		1,578,970		1,573,596


	Three Months Ended June 30,				% Change								Six Months Ended June 30,								% Change
Electric Revenue	2012		2011									2012				2011					% Change
Retail Delivery and Sales(a)					% Change
Residential	$	393	$	451		(12.9	)%						$	800			$	944				(15.3	)%
Small commercial & industrial		119		165		(27.9	)%							237				334				(29.0	)%
Large commercial & industrial		58		67		(13.4	)%							111				175				(36.6	)%
Public authorities & electric railroads		8		9		(11.1	)%							16				20				(20.0	)%

Total Retail		578		692		(16.5	)%							1,164				1,473				(21.0	)%

Other Revenue(b)		57		61		(6.6	)%							114				126				(9.5	)%

Total Electric Revenues	$	635	$	753		(15.7	)%						$	1,278			$	1,599				(20.1	)%


Number of Electric Customers	As of September 30,
Number of Electric Customers	2012		2011
Residential		1,416,894		1,412,059
Small commercial & industrial		148,829		148,210
Large commercial & industrial		3,103		3,116
Public authorities & electric railroads		9,666		9,693

Total		1,578,492		1,573,078


	Three Months Ended September 30,				% Change			Nine Months Ended September 30,				% Change
Electric Revenue	2012		2011		% Change			2012		2011		% Change
Retail Delivery and Sales(a)
Residential	$	497	$	598		(16.9	)%	$	1,297	$	1,542		(15.9	)%
Small commercial & industrial		120		138		(13.0	)%		357		472		(24.4	)%
Large commercial & industrial		66		85		(22.4	)%		179		261		(31.4	)%
Public authorities & electric railroads		8		9		(11.1	)%		24		29		(17.2	)%

Total Retail		691		830		(16.7	)%		1,857		2,304		(19.4	)%

Other Revenue(b)		61		61		0.0	%		171		183		(6.6	)%

Total Electric Revenues	$	752	$	891		(15.6	)%	$	2,028	$	2,487		(18.5	)%



	Three Months Ended June 30,				% Change				Weather- Normal % Change				Six Months Ended June 30,					% Change			Weather- Normal % Change
Deliveries to customers (in mmcf)																Three Months Ended September 30,								% Change				Weather- Normal % Change			Nine Months Ended September 30,							% Change			Weather- Normal % Change
	2012		2011					% Change						Weather- Normal % Change			2012			2011							% Change					Weather- Normal % Change			2012					2011						2012			2011
Retail Delivery and Sales
Retail sales(a)		6,228		6,561		(5.1	)%						(1.1	)%		28,655			35,295			(18.8	)%			0.8	%			3,646				3,687			(1.1	)%		(3.0		)%		32,301			38,982			(17.1	)%	0.5	%
Transportation and other		5,835		6,278		(7.1	)%			(6.7	)%			13,601			15,238		(10.7	)%		(9.4	)%			5,796				6,190			(6.4	)%		(5.3	)%		19,397				21,428		(9.5	)%		(8.2	)%

Total Gas Deliveries		12,063		12,839		(6.0	)%			(3.7	)%			42,256			50,533		(16.4	)%		(2.2	)%			9,442				9,877			(4.4	)%		(4.4	)%		51,698				60,410		(14.4	)%		(2.5	)%


	As of June 30,																								As of September 30,
Number of Gas Customers	2012		2011																						2012				2011
Residential		452,478		449,066																						452,624				448,763
Commercial & industrial		41,383		40,956																						41,338				40,883

Total Retail		493,861		490,022																						493,962				489,646
Transportation		888		864																						900				868

Total		494,749		490,886																						494,862				490,514


	Three Months Ended June 30,				% Change								Six Months Ended June 30,					% Change
Gas revenue	2012		2011									2012			2011
Retail Delivery and Sales
Retail sales(a)	$	73	$	82		(11.0	)%						$	295		$	378		(22.0	)%
Transportation and other		7		7		0.0	%							17			19		(10.5	)%

Total Gas Deliveries	$	80	$	89		(10.1	)%						$	312		$	397		(21.4	)%


	Three Months Ended September 30,				% Change			Nine Months Ended September 30,				% Change
Gas revenue	2012		2011		% Change			2012		2011		% Change
Retail Delivery and Sales
Retail sales(a)	$	49	$	51		(3.9	)%	$	344	$	429		(19.8	)%
Transportation and other		5		4		25.0	%		24		26		(7.7	)%

Total Gas Deliveries	$	54	$	55		(1.8	)%	$	368	$	455		(19.1	)%


	Three Months Ended June 30,						Favorable (Unfavorable) Variance				Six Months Ended June 30,							Favorable (Unfavorable) Variance				Three Months Ended September 30,							Favorable (Unfavorable) Variance				Nine Months Ended September 30,							Favorable (Unfavorable) Variance
	2012			2011						2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance			2012				2011				Favorable (Unfavorable) Variance
Operating revenues	$	616		$	674		Favorable (Unfavorable) Variance	$	(58	)		$	1,312			$	1,650		$	(338	)		$	720			$	745		$	(25	)		$	2,032			$	2,394		$	(362	)
Purchased power and fuel		285			340			55				670				883			213				373				405			32				1,043				1,288			245

Revenue net of purchased power and fuel(a)		331			334			(3	)			642				767			(125	)			347				340			7				989				1,106			(117	)

Other operating expenses
Operating and maintenance		161			167			6				356				319			(37	)			201				210			9				557				529			(28	)
Depreciation and amortization		71			67			(4	)			150				144			(6	)			68				60			(8	)			218				205			(13	)
Taxes other than income		47			46			(1	)			95				96			1				48				47			(1	)			143				143			—

Total other operating expenses		279			280			1				601				559			(42	)			317				317			—				918				877			(41	)

Operating income		52			54			(2	)			41				208			(167	)			30				23			7				71				229			(158	)

Other income and (deductions)
Interest expense, net		(34	)		(32	)		(2	)			(75	)			(66	)		(9	)			(35	)			(32	)		(3	)			(110	)			(97	)		(13	)
Other, net		7			6			1				13				13			—				5				8			(3	)			18				22			(4	)

Total other income and (deductions)		(27	)		(26	)		(1	)			(62	)			(53	)		(9	)			(30	)			(24	)		(6	)			(92	)			(75	)		(17	)

Income (loss) before income taxes		25			28			(3	)			(21	)			155			(176	)			—				(1	)		1				(21	)			154			(175	)
Income taxes		9			12			3				(7	)			58			65				—				(3	)		(3	)			(7	)			55			62

Net income (loss)		16			16			—				(14	)			97			(111	)			—				2			(2	)			(14	)			99			(113	)
Preference stock dividends		3			3			—				6				6			—				4				4			—				10				10			—

Net income (loss) on common stock	$	13		$	13		$	—			$	(20	)		$	91		$	(111	)		$	(4	)		$	(2	)	$	(2	)		$	(24	)		$	89		$	(113	)

Net income for the three months ended ~~June~~September 30, 2012 compared to the same period in 2011 was relatively consistent. The decrease in net income for the ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 was driven primarily by decreased operating revenue net of purchased power and fuel expense related to the accrual of the residential customer rate credit to be provided as a condition of the MDPSC’s approval of Exelon’s merger with Constellation. The decrease in net income was also driven by increased operating and maintenance expenses, primarily related to BGE’s accrual of its portion of the charitable contributions to be provided as a condition of the MDPSC’s approval of the merger as well as merger transaction costs. None of the customer rate credit, the charitable contributions, or the transaction costs are recoverable from BGE’s customers.

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 programs allowing customers to select a competitive

electric or natural gas supplier. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.

The number of customers electing to select a competitive electric generation supplier affects electric SOS revenues and purchased power expense. The number of customers electing to select a competitive natural gas supplier affects gas cost adjustment revenues and purchased natural gas expense. All BGE customers have the choice to purchase energy from a competitive electric generation supplier. This customer choice of electric generation suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to SOS. The number of retail customers purchasing electricity from a competitive electric generation supplier was ~~338,400~~347,200 and ~~278,400~~297,000 at ~~June~~September 30, 2012 and 2011, respectively, representing ~~27%~~28% and ~~22%~~24% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented ~~62%~~59% and ~~61%~~60% of BGE’s retail kWh sales for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively compared to ~~60%~~58% and 57% for the three and ~~six~~nine months ended ~~June~~September 30, 2011, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was ~~125,300~~132,800 and ~~106,700~~112,200 at ~~June~~September 30, 2012 and 2011, respectively, representing ~~19%~~20% and ~~16%~~17% of total retail customers, respectively. Retail deliveries purchased from competitive natural gas suppliers represented ~~68%~~74% and ~~55%~~58% of BGE’s retail mmcf sales for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, compared to ~~63%~~75% and ~~47%~~52% for the three and ~~six~~nine months ended ~~June~~September 30, 2011, respectively.

The changes in BGE’s operating revenues net of purchased power and fuel expense for the three months ended compared to the same period in 2011, consisted of the following:


	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas		Total
Regulatory required programs	$	2		$	1		$	3		$	6		$	—	$	6
Transmission											4			—		4
Other		(5	)		(1	)		(6	)		(5	)		2		(3	)

Total decrease	$	(3	)	$	—		$	(3	)
Total increase										$	5		$	2	$	7

The changes in BGE’s operating revenues net of purchased power and fuel expense for the ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 consisted of the following:


	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Residential customer rate credit(a)	$	(82	)	$	(31	)	$	(113	)	$	(82	)	$	(31	)	$	(113	)
Commodity margin											(2	)		(4	)		(6	)
Regulatory required programs		2			2			4			8			2			10
Commodity margin		(2	)		(4	)		(6	)
Transmission											7			—			7
Other		(4	)		(6	)		(10	)		(11	)		(4	)		(15	)

Total increase	$	(86	)	$	(39	)	$	(125	)
Total decrease										$	(80	)	$	(37	)	$	(117	)

Revenue Decoupling.The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE to record a monthly adjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution

revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at MDPSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

Volume.Heating degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating degree days in BGE’s service territory for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 consisted of the following:


							% Change												% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal			2012		2011		Normal		From 2011			From Normal
Three Months Ended June 30,
Three Months Ended September 30,
Heating Degree-Days		402		392		522		2.6	%		(23.0	)%		69		49		83		40.8	%		(16.9	)%
Cooling Degree-Days		289		342		246		(15.5	)%		17.5	%		698		677		583		3.1	%		19.7	%

Six Months Ended June 30,
Nine Months Ended September 30,
Heating Degree-Days		2,275		2,841		2,936		(19.9	)%		(22.5	)%		2,344		2,890		3,019		(18.9	)%		(22.4	)%
Cooling Degree-Days		299		344		249		(13.1	)%		20.1	%		997		1,021		832		(2.4	)%		19.8	%

Residential Customer Rate Credit.The residential customer rate credit provided as a result of the MDPSC’s order approving Exelon’s merger with Constellation decreased operating revenues net of purchased power and fuel expense for the ~~six~~nine months ended ~~June~~September 30, 2012.

Commodity Margin. The commodity margin for both electric and gas revenues decreased during the nine months ended September 30, 2012 compared to the same period in 2011. Commodity revenues are affected by the number of customers using competitive suppliers as well as the cost of purchased power and natural gas.

Regulatory Required Programs.This represents the change in revenues collected under approved riders to recover costs incurred for the energy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to provide full recovery, as

well as a return in certain instances. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and taxes other than income taxes. The increase in revenues during the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011 was due to the recovery of higher energy efficiency program costs.

~~Commodity Margin.~~Transmission ~~The commodity margin for both electric and gas~~. Transmission revenues ~~decreased~~increased during the ~~six~~three and nine months ended ~~June~~September 30, 2012 compared to the same period in 2011. ~~Commodity revenues~~BGE’s transmission rates are ~~affected~~established based on a FERC-approved formula. The rates also include transmission investment incentives approved by ~~the~~FERC in a number of ~~customers using competitive suppliers as well as the cost of purchased power and natural gas.~~orders covering various new transmission investment projects since 2007.

Other. Other revenues decreased during the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same period in 2011. Other revenues, which can vary from period to period, include ~~transmission revenues and other~~ miscellaneous revenues such as late payment charge revenues and all base distribution revenues, which decreased due to lower volumes and customer mix. .


	Three Months Ended September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
Operating and Maintenance Expense —Baseline	$	201	$	210	$	(9	)	$	557	$	529	$	28
Operating and Maintenance Expense —Regulatory Required Programs(a)		—		—		—			—		—		—

Total Operating and Maintenance Expense		201		210		(9	)		557		529		28

The changes in operating and maintenance expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011, consisted of the following:


	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)			Increase (Decrease)			Increase (Decrease)			Increase (Decrease)
Baseline
Charitable contributions accrual(a)	$	—		$	28		$	—		$	28
Storm costs deferral(b)		—			16			—			16
Merger transaction costs(a)		(7	)		5			(1	)		6
Pension and non-pension postretirement benefits expense								1			3
Uncollectible accounts expense								1			3
Storm-related costs(c)								(3	)		(15	)
Labor, other benefits, contracting and materials		(1	)		(7	)		(9	)		(14	)
Pension Benefits		1			2
Storm-related costs(c)		3			(11	)
Other		(2	)		4			2			1

		(6	)		37			(9	)		28
Regulatory Required Programs
SOS		—			—			—			—

(Decrease) increase in operating and maintenance expense	$	(6	)	$	37		$	(9	)	$	28

The increase in depreciation and amortization expense for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 was primarily due to higher plant balances. Additionally, depreciation and amortization expense includes amortization expense related to energy efficiency and demand response programs which isare fully offset in revenues above.

Taxes other than income remained relatively consistent for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011.

The increase in interest expense, net for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in 2011 was primarily due to higher outstanding debt balances as well as interest recorded on prior year tax ~~liabilities as well as higher outstanding debt balances.~~liabilities.

The decrease in Other, net ~~remained consistent~~ for the three and ~~six~~nine months ended ~~June~~September 30, 2012 compared to the same periods in ~~2011.~~2011 was primarily due to decreased AFUDC-Equity and investment income. See Note 17 of the Combined Notes to Consolidated Financial Statements for further details of the components of Other, net.

BGE’s effective income tax rate was ~~36.0%~~0.0% and ~~42.9%~~300.0% for the three months ended ~~June~~September 30, 2012 and 2011, respectively, and 33.3% and ~~37.4%~~35.7% for the ~~six~~nine months ended ~~June~~September 30, 2012 2011, respectively. See Note 10 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax rate.


Retail Deliveries to customers (in GWhs)	Three Months Ended June 30,				% Change				Weather- Normal % Change		Six Months Ended June 30,							% Change				Weather- Normal % Change		Three Months Ended September 30,				% Change				Weather- Normal % Change				Nine Months Ended September 30,						% Change			Weather- Normal % Change
Retail Deliveries to customers (in GWhs)	2012		2011					2012				2011					2012						2011				2012				2011											% Change			Weather- Normal % Change
Retail Delivery and Sales(a)					% Change
Residential		2,663		2,751		(3.2	)%		Weather- Normal % Change	n.m			5,865			6,276		% Change			(6.5	Weather- Normal % Change	)%		n.m	3,829		% Change	3,695			Weather- Normal % Change		3.6	%			n.m			9,693			9,971			(2.8	)%	n.m
Small commercial & industrial		4,035		4,156		(2.9	)%		n.m			7,816			8,073				(3.2	)%		n.m			4,458		4,432		0.6	%			n.m				12,273			12,505			(1.9	)%		n.m
Large commercial & industrial		637		617		3.2	%		n.m			1,259			1,154				9.1	%		n.m			462		665		(30.5	)%			n.m				1,721			1,819			(5.4	)%		n.m
Public authorities & electric railroads		48		108		(55.6	)%		n.m			96			209				(54.1	)%		n.m			47		99		(52.5	)%			n.m				143			308			(53.6	)%		n.m

Total Electric Retail		7,383		7,632		(3.3	)%		n.m			15,036			15,712				(4.3	)%		n.m			8,796		8,891		(1.1	)%			n.m				23,830			24,603			(3.1	)%		n.m


	As of June 30,																							As of September 30,
Number of Electric Customers	2012		2011																					2012		2011
Residential		1,115,107		1,115,989																					1,115,764		1,115,279
Small commercial & industrial		119,338		118,274																					119,431		118,451
Large commercial & industrial		5,432		5,443																					5,448		5,550
Public authorities & electric railroads		296		326																					318		326

Total		1,240,173		1,240,032																					1,240,961		1,239,606


	Three Months Ended June 30,				% Change						Six Months Ended June 30,							% Change						Three Months Ended September 30,				% Change								Nine Months Ended September 30,						% Change
Electric Revenue	2012		2011					2012				2011						% Change			2012				2011			% Change					2012				2011					% Change
Retail Delivery and Sales(a)					% Change
Residential	$	295	$	326		(9.5	)%				$	560		$	749				(25.2	)%				$	400	$	408		(2.0	)%						$	960		$	1,157			(17.0	)%
Small commercial & industrial		149		161		(7.5	)%					298			328				(9.1	)%					166		172		(3.5	)%							464			500			(7.2	)%
Large commercial & industrial		10		14		(28.6	)%					20			27				(25.9	)%					10		13		(23.1	)%							31			40			(22.5	)%
Public authorities & electric railroads		7		7		0.0	%					15			15				0.0	%					8		8		0.0	%							22			22			0.0	%

Total Retail		461		508		(9.3	)%					893			1,119				(20.2	)%					584		601		(2.8	)%							1,477			1,719			(14.1	)%

Other Revenue		57		57		0.0	%					114			115				(0.9	)%					64		60		6.7	%							177			175			1.1	%

Total Electric Revenues	$	518	$	565		(8.3	)%				$	1,007		$	1,234				(18.4	)%				$	648	$	661		(2.0	)%						$	1,654		$	1,894			(12.7	)%


	Three Months Ended June 30,				% Change				Weather- Normal % Change		Six Months Ended June 30,							% Change				Weather- Normal % Change		Three Months Ended September 30,				% Change				Weather- Normal % Change				Nine Months Ended September 30,						% Change			Weather- Normal % Change
Deliveries to customers (in mmcf)	2012		2011					2012				2011					2012						2011				2012				2011											% Change			Weather- Normal % Change
Retail Delivery and Sales(b)					% Change
Retail sales		15,535		14,407		7.8	%		Weather- Normal % Change	n.m.			49,466			56,485		% Change			(12.4	Weather- Normal % Change	)%		n.m.	11,147		% Change	12,628			Weather- Normal % Change		(11.7	)%			n.m.			60,613			69,113			(12.3	)%	n.m.
Transportation and other		4,854		4,028		20.5	%		n.m.			10,295			9,582				7.4	%		n.m.			2,311		3,489		(33.8	)%			n.m.				12,606			13,071			(3.6	)%		n.m.

Total Gas Deliveries		20,389		18,435		10.6	%		n.m.			59,761			66,067				(9.5	)%		n.m.			13,458		16,117		(16.5	)%			n.m.				73,219			82,184			(10.9	)%		n.m.


	As of June 30,																							As of September 30,
Number of Gas Customers	2012		2011																					2012		2011
Residential		610,073		608,945																					610,353		608,267
Commercial & industrial		44,011		43,953																					43,978		43,979

Total		654,084		652,898																					654,331		652,246


	Three Months Ended June 30,				% Change						Six Months Ended June 30,							% Change						Three Months Ended September 30,				% Change								Nine Months Ended September 30,						% Change
Gas revenue	2012		2011					2012				2011						% Change			2012				2011			% Change					2012				2011					% Change
Retail Delivery and Sales					% Change
Retail sales	$	84	$	87		(3.4	)%				$	272		$	359				(24.2	)%				$	63	$	66		(4.5	)%						$	335		$	425			(21.2	)%
Transportation and other(b)		14		22		(36.4	)%					33			57				(42.1	)%					9		18		(50.0	)%							43			75			(42.7	)%

Total Gas Deliveries	$	98	$	109		(10.1	)%				$	305		$	416				(26.7	)%				$	72	$	84		(14.3	)%						$	378		$	500			(24.4	)%

Exelon and Generation activity presented below includes the activity of Constellation, and BGE in the case of Exelon, from the merger effective date of March 12, 2012 through ~~June~~September 30, 2012. Exelon and Generation prior year activity is unadjusted for the effects of the merger. BGE activity presented below includes its activity for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011.

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, PECO and BGE have access to unsecured revolving credit facilities with aggregate bank commitments of ~~$2.9~~$2.0 billion, $5.6 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. The Registrants’ revolving credit facilities expire between ~~October 2013~~December 2012 and ~~March~~August 2017. The bilateral ~~facilities~~facility at ~~Exelon~~Generation has expirations in December 2015 and ~~Generation have expirations that range from September 2013 through~~ March 2016. The Registrants 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, PECO and BGE 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 9 of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.

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, PECO’s and BGE’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO and BGE, gas distribution services. ComEd’s, PECO’s and BGE’s distribution services are provided to an established and diverse base of retail customers. ComEd’s, PECO’s and BGE’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 4 and 16 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plans. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

For financial reporting purposes, the unfunded status of Exelon’s plans is updated annually, at December 31, unless there is a significant event such as a major plan amendment, settlement, or curtailment. Effective March 12, 2012, Exelon became the sponsor of all of Constellation’s defined benefit pension and other postretirement benefit plans. As a result of employee severances related to the merger, a curtailment was triggered for certain legacy Constellation pension and other postretirement benefit plans in the second quarter of 2012. Accordingly, the benefit obligation and plan assets for those plans were remeasured using assumptions as of June 30, 2012. The discount rates used to calculate the curtailed pension and other postretirement benefit plan obligations as of June 30, 2012 were 3.97% and 3.98%, respectively. During the third quarter of 2012, Exelon announced plan design changes for certain legacy Exelon and Constellation other postretirement benefit plans, requiring an interim remeasurement of the benefit obligation and assets for those plans using assumptions as of September 30, 2012. The discount rates used to calculate the other postretirement benefit plan obligations for legacy Exelon and Constellation were 3.93% and 3.72%, respectively, as of September 30, 2012. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information on the impact of the remeasurements on the financial statements.

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 other postretirement benefit plans at ~~June~~September 30, 2012 by updating the most significant assumptions affecting plan obligations and assets, which are the discount rate and current year’s plan asset investment performance. The discount rates for legacy Exelon’s pension and other postretirement benefit plans were ~~4.15%~~3.84% and ~~4.23%~~3.93%, respectively, at ~~June~~September 30, 2012. The discount ~~rates~~rate was 3.64% for legacy Constellation’s pension plans and ranged from

3.66% to 3.72% for legacy Constellation’s other postretirement benefit plans ~~were 3.97% and 3.98%, respectively,~~ at ~~June~~September 30, ~~2012, which are consistent with the discount rates used above in connection with the curtailment remeasurement of certain legacy Constellation plans.~~2012. Additionally, Exelon’s pension and ~~funded~~ other postretirement benefit plans experienced actual asset returns of approximately ~~5.70% and 5.40%, respectively,~~10% for the ~~six~~nine months ended ~~June~~September 30, 2012.

Based on these assumptions, Exelon has estimated the unfunded status of the pension and other postretirement benefit plans at ~~June~~September 30, 2012 to be ~~$3,545~~$3,926 million and ~~$3,020~~$2,999 million, respectively, representing a funded status percentage of ~~79%~~78% and ~~37%~~38%, respectively. The unfunded status of Exelon’s pension and other postretirement benefit plans increased ~~$1,309~~$1,690 million and ~~$755~~$734 million, respectively, since December 31, 2011

primarily due to the acquisition of Constellation’s pension and other postretirement benefit plans, growth in benefit obligations as a result of service and interest cost, a decrease in Exelon’s discount rates and demographic losses based on Exelon’s updated valuation, partially offset by favorable asset returns as of ~~June~~September 30, 2012. ~~Legacy Constellation asset returns are~~During the fourth quarter of 2012, Exelon will complete an optional lump sum election program for select participants in certain of its qualified pension plans, which will reduce the ~~period after March 12, 2012.~~obligation and plan assets associated with those plans.

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law will be applied in 2012 while others take effect in 2013. The estimated impacts of the law are reflected in the projected pension contributions below.

Exelon expects to contribute ~~$83~~$77 million to its qualified pension plans in 2012, of which Generation, ComEd and PECO will contribute ~~$51~~$46 million, $9 million and ~~$12~~$13 million, respectively. Legacy Constellation’s 2011 pension contributions included an acceleration of estimated calendar year 2012 contributions. Therefore, BGE does not anticipate any qualified pension contributions in 2012. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $67 million in 2012, of which Generation, ComEd, PECO, and BGE will make payments of $9 million, $14 million, $1 million, and $1 million, respectively.

Management has estimated its future pension contributions at ~~June~~September 30, 2012, incorporating updated projected discount rates and anticipated employee severances as a result of the merger. 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~~plans. Additionally, for Exelon’s largest qualified pension plan, the contributions ~~Exelon may elect~~below reflect a funding strategy of contributing the greater of $250 million, which approximates service cost, or the minimum amounts under ERISA to ~~make in these~~avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future ~~periods. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a~~period required pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law will be applied in 2012 while others take effect in 2013. The estimated impacts of the law are reflected in the projected pension contributions below.contributions.

To the extent interest rates continue to decline or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase and such increases could be significant, especially in years 2015 and beyond. Additionally, the projected contributions above could change if Exelon changes its pension funding strategy.

level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). In 2012, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans previously sponsored by Constellation and AmerGen, which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $318 million in 2012, of which Generation, ComEd, PECO and BGE expect to contribute ~~$132~~$131 million, $116 million, ~~$34~~$33 million and ~~$14~~$13 million, respectively. This total excludes $4 million in 2012 other postretirement benefit plan ~~contributions~~payments made by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012. Based on the current funding strategy, the Registrants expect to contribute an aggregate of approximately ~~$260~~$250 million — $305 million annually from 2013 to 2017 to the other postretirement benefit plans.

The Registrants’ future cash flows from operating activities may be affected by the following tax matters:

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:


	Nine Months Ended September 30,
	2012			2011			Variance
Net income	$	787		$	1,889		$	(1,102	)
Add (subtract):
Non-cash operating activities(a)		4,166			3,863			303
Pension and other postretirement benefit contributions		(131	)		(2,089	)		1,958
Income taxes		465			532			(67	)
Changes in working capital and other noncurrent assets and liabilities(b)		(1,016	)		(530	)		(486	)
Option premiums (paid) received, net		(122	)		59			(181	)
Counterparty collateral received (posted), net		408			(807	)		1,215

Net cash flows provided by operations	$	4,557		$	2,917		$	1,640

Cash flows provided by operations for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 by Registrant were as follows:


	Six Months Ended June 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Exelon	$	2,729	$	1,013	$	4,557	$	2,917
Generation		1,866		1,076		3,013		2,122
ComEd		722		71		1,181		615
PECO		409		359		628		656
BGE		369		473		323		427

Changes in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 were as follows:

posted with PJM decreased during the six months ended June 30, 2012 due to a $14 million decrease for seasonal variations, lower market capacity and energy prices and customer load migration, partially offset by a $7 million increase for the reallocation of the $50 million unsecured credit level afforded to Exelon amongst a greater number of subsidiaries following the merger with Constellation. As of June 30, 2012 and 2011, ComEd had $84 million and $125 million, respectively, of collateral remaining at PJM.

Cash flows used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 by Registrant were as follows:


	Six Months Ended June 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Exelon	$	(1,984	)	$	(2,074	)	$	(3,325	)	$	(4,031	)
Generation		(1,284	)		(1,388	)		(2,056	)		(2,421	)
ComEd		(567	)		(473	)		(871	)		(1,276	)
PECO		(157	)		(371	)		(259	)		(402	)
BGE		(284	)		(279	)		(413	)		(438	)

Capital expenditures by Registrant for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 and projected amounts for the full year 2012 are as follows:


	Projected Full Year 2012				Six Months Ended June 30,						Projected Full Year 2012				Nine Months Ended September 30,
				2012				2011			Projected Full Year 2012			2012				2011
Exelon	Projected Full Year 2012	$	6,226			$	2,816		$	1,985		$	6,059			$	4,145		$	2,972
Generation(a)		3,914				1,820			1,270			3,796				2,602			1,865
ComEd(b)		1,282				585			495			1,264				896			758
PECO		433				179			209			434				274			321
BGE(d)		542				282			283			573				402			416
Other(c)		55				30			11			63				38			28

(b)

The projected capital expenditures include approximately ~~$200~~$170 million in incremental spending related to ComEd’s 2012 investment plan filed with the ICC on January 6, 2012. Pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over the next ten years to modernize and storm-harden its distribution system and to implement smart grid technology.

(c)	Other primarily consists of corporate operations and BSC.

(d)	The projected capital expenditures include those incurred prior to the merger on March 12, 2012.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Approximately ~~33%~~34% and 30% of the projected 2012 capital expenditures at Generation are for investments in renewable energy generation, including Antelope Valley and Exelon Wind construction costs, and the acquisition of nuclear fuel, respectively. The remaining amounts primarily reflect additions and upgrades to existing facilities including material condition improvements during nuclear refueling outages. Also included in the projected 2012 capital expenditures are a portion of the costs of a series of planned power uprates across Generation’s nuclear fleet. ~~A review of the LaSalle Extended Power Uprate was performed this quarter and the completion of the project was deferred by two years, primarily as~~As a result of ~~market conditions.~~the decision to defer or cancel certain projects from the uprate program, 2012 projected capital expenditures reflect a reduction of approximately $50 million associated with the decision to defer or cancel certain projects from the uprate program. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.

On August 8, 2012, a subsidiary of Generation reached an agreement to sell three Maryland generating stations and associated assets to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC. Generation expects to receive estimated proceeds of approximately ~~$400~~$388 million ~~less transaction costs of approximately $20 million at or around closing of the transaction~~ in the fourth quarter ~~of 2012. In addition, under the terms of the agreement, Generation will make~~less cash payments of approximately ~~$25~~$32 million to Raven Power Holdings LLC over a twelve-month period beginning in June 2014. Generation expects to incur transaction costs of approximately $20 million through the date of closing of the transaction which is expected in the fourth quarter of 2012. The sale will generate approximately ~~$205~~$225 million of cash tax benefits, of which $135 million will be realized in periods through 2013 with the balance to be received in later years. Therefore, Generation expects net after-tax cash sale proceeds of approximately ~~$435~~$500 million ~~in 2012, approximately $80 million in~~through 2013 and approximately ~~$45~~$65 million in 2014 and subsequent years. Net after-tax cash sales proceeds for 2012 are approximately $170 million lower than prior projections, of which approximately $70 million will be reversed in 2013. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on the sale.

Approximately ~~82%~~83%, ~~70%~~66% and ~~71%~~70% of the projected 2012 capital expenditures at ComEd, PECO and BGE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and ComEd’s, PECO’s and BGE’s construction commitments under PJM’s RTEP. The remaining amounts are for capital additions to support new business and customer growth, which for ComEd

includes capital expenditures related to smart grid/smart meter technology required under EIMA, and for PECO and BGE includes capital expenditures related to their smart meter program and SGIG project, net of DOE expected reimbursements.

As a result of the October 3, 2012 ICC Rehearing Order, ComEd currently plans to defer approximately $450 million of smart meter and other infrastructure spend from the period 2012-2014 to 2015 and beyond. The 2012 projected capital expenditures reflect a reduction of approximately $65 million related to the deferral of ComEd’s original investment plan filed with the ICC on January 6, 2012. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

In 2010, NERC provided guidance to transmission owners that recommends ComEd, PECO and BGE perform assessments of all their transmission lines, with the highest priority lines assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority lines by December 31, 2013. In compliance with this guidance, ComEd, PECO and BGE submitted their most recent bi-annual reports to NERC in July 2012. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2012 capital expenditures above reflect capital spending for remediation to be completed in 2012.

ComEd, PECO and BGE anticipate that they will fund their capital expenditures with internally generated funds and borrowings, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 4 of the Combined Notes to Consolidated Financial Statements.

Cash flows provided by (used in) financing activities for the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 by Registrant were as follows:


	Six Months Ended June 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Exelon	$	(412	)	$	11		$	(548	)	$	573
Generation		(148	)		(35	)		(623	)		(14	)
ComEd		(360	)		446			(513	)		967
PECO		(174	)		(191	)		85			(258	)
BGE		(81	)		(123	)		162			12

See Note 9 of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.

Cash dividend payments and distributions during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011 by Registrant were as follows:


	Six Months Ended June 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
Exelon	$	824	$	695		$	1,226	$	1,044
Generation		891		—			1,384		61
ComEd		85		150			95		225
PECO		174		186			261		271
BGE		6		91	(a)		10		95	(a)

On January 24, 2012, the Exelon Board of Directors declared a second quarter 2012 regular quarterly dividend of $0.525 per share on Exelon’s common stock contingent on the merger with Constellation. Based on the effective date of the merger, shareholders received two separate dividend payments totaling $0.525 per share as follows:

per share per day for the period from and including the effective date of the merger (March 12, 2012) through and including May 15, 2012. This portion of the dividend, totaling approximately $323 million, was paid on June 8, 2012.

On July 24, 2012, the Exelon Board of Directors declared a regular quarterly dividend, paid on September 10, 2012 of $0.525 per share on Exelon’s common stock.

On October 22, 2012 the Exelon Board of Directors declared a regular quarterly dividend, payable on ~~September~~December 10, 2012 of $0.525 per share on Exelon’s common stock.

During the ~~six~~nine months ended ~~June~~September 30, 2012, Exelon ~~issued $27~~repaid $146 million of outstanding commercial paper, ComEd issued ~~$178~~$35 million of commercial paper and Generation repaid ~~$26~~$25 million in short-term notes payable. During the ~~six~~nine months ended ~~June~~September 30, 2011, Exelon issued ~~$140~~$389 million of commercial paper and Generation issued $73 million of commercial paper.

During the ~~six~~nine months ended ~~June~~September 30, 2012, Exelon contributed $66 million to BGE to fund the after-tax amount of the residential customer rate credit as directed in the MDPSC order approving the merger transaction. ~~There were no contributions from Parent/Member (Exelon) during~~During the ~~six~~nine months ended ~~June~~September 30, ~~2011.~~2011, Exelon contributed $30 million and $18 million to Generation and PECO, respectively.

For the ~~six~~nine months ended ~~June~~September 30, 2012, other financing activities primarily consists of expenses paid related to the replacement of the Registrants’ credit facilities. See Note 9 of the Combined Notes to Consolidated Financial Statements for additional information.

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 ~~$10.7~~$9.8 billion in aggregate total commitments of which ~~$8.0~~$7.5 billion was available as of ~~June~~September 30, 2012, and of which no financial institution has more than 10% of the aggregate commitments. Exelon, Generation, ComEd, PECO and BGE had access to the commercial paper market during the ~~second~~third quarter of 2012 to fund their short-term liquidity needs, when necessary. 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 2011 Annual Report on Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets or significant bank failures.

The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of ~~June~~September 30, 2012, it would have been required to provide incremental collateral of ~~$2.4~~$2.0 billion, which is well within its current available credit facility capacities of ~~$3.8~~$3.5 billion, which includes collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements. If ComEd lost its investment grade credit rating as of ~~June~~September 30, 2012, it would have been required to provide incremental collateral of $218 million, which is well within its current available credit facility capacity of ~~$821~~$844 million, which takes into account commercial paper

borrowings as of ~~June~~September 30, 2012. If PECO lost its investment grade credit rating as of ~~June~~September 30, 2012, it would ~~not~~ have been required to provide collateral of $1 million pursuant to PJM’s credit policy and could have been required to provide collateral of ~~$36~~$30 million related to its natural gas procurement contracts, which, in the aggregate, is well within PECO’s current available credit facility capacity of $599 million. If BGE lost its investment grade credit rating as of ~~June~~September 30, 2012, it would have been required to provide collateral of $3 million pursuant to PJM’s credit policy and could have been required to provide collateral of ~~$54~~$51 million related to its natural gas procurement contracts, which, in the aggregate, is well within BGE’s current available credit facility capacity of ~~$599~~$499 million.

Exelon, ComEd and BGE meet their 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. 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 9 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at ~~June~~September 30, 2012:

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.

On October 19, 2012, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new minority and community bank credit facility agreements in the amounts of $50 million, $34 million and $34 million, respectively, and BGE entered into a minority and community bank credit facility in the amount of $5 million. These facilities, which expire in October 2013, are solely utilized to issue letters of credit.

A subsidiary of Generation also has a three-year senior secured credit facility associated with certain solar projects. The amount committed under the facility is $150 million, which may be increased up to a total amount of $200 million at the subsidiary’s request with additional commitments by the lenders. Obligations under this facility are secured by the equity interests in the subsidiary and the entities that own the solar projects as well as the assets of the subsidiary of each project entity and are guaranteed by Generation and the project entities. As of ~~June~~September 30, 2012, the outstanding loan balance was ~~$124~~$117 million.

CEU, a subsidiary of Generation, has a reserve-based lending facility that supports the upstream gas operations. The borrowing base committed under the facility is $150 million and can grow up to $500 million if the assets support a higher borrowing base and if CEU is able to obtain additional commitments from lenders. The facility expires in July 2016 and any borrowings under this facility are secured by the upstream gas properties. As of ~~June~~September 30, 2012, the outstanding loan balance was ~~$37~~$75 million.

On March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new unsecured facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement has an initial term expiring on March 28, 2017, and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to amend and extend the facilities for ComEd were not material.

Borrowings under the credit agreement may bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon ComEd’s credit rating. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The fee varies depending upon ComEd’s credit rating. The credit agreement also requires ComEd to pay a facility fee based upon the aggregate commitments under the agreement.

On August 10, 2012, Exelon Corporate, Generation, PECO and BGE amended and extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, through August 10, 2017. Under these facilities Exelon Corporate, Generation, PECO and BGE may issue letters of credit in the aggregate of up to $200 million, $3.5 billion, $300 million and $600 million, respectively. Each credit facility permits the applicable borrower to request extensions for up to two additional one-year periods. Each credit facility also allows Exelon Corporate, Generation, PECO and BGE to request increases in aggregate commitments up to an additional $250 million, $1.0 billion, $250 million and $100 million, respectively. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material.

The amended credit facilities updated the credit ratings-based pricing grids used to determine the facility fee and interest rates for borrowings under each ~~revolving~~facility and reflect current market pricing and maturities of five years from the close of the transactions. Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon ~~either~~ the prime rate or ~~at a fixed rate for a specified period based~~ upon a LIBOR-based rate. ~~The agreements also provide for adders based upon the credit rating of the borrower. Under the ComEd agreement executed on March 28, 2012,~~Exelon Corporate, Generation, PECO and BGE had adders of ~~up to 65~~27.5, 7.5, 0.0 and 7.5 basis points for prime-based borrowings and ~~165~~127.5, 107.5, 100.0 and 107.5 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings ~~may be added based upon ComEd’s credit rating. At June 30, 2012, ComEd’s adder was 27.5~~and LIBOR-based rate borrowings are 65 basis points ~~for prime based borrowings~~ and ~~127.5~~165 basis points, ~~for LIBOR-based borrowings.~~

~~Under~~respectively. The covenants in each of Exelon Corporate, Generation, PECO and BGE’s extended facilities are substantially consistent with existing covenants, with the Exelon and Generation bilateral and commodity-linked credit agreements, Exelon and Generation pay a facility fee, payable quarterly at a rate per annum equal to a specified facility fee rate on the total amountexception of the ~~credit~~BGE facility, ~~regardless of usage.~~in which a debt to capitalization financial covenant was replaced with an interest coverage ratio financial covenant.

Each revolving credit agreement for Exelon, Generation, ComEd, PECO and ~~PECO~~BGE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the ~~twelve-month~~twelve- month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the ~~six~~nine months ended ~~June~~September 30, 2012:

At ~~June~~September 30, 2012, the interest coverage ratios at the Registrants were as follows:

The BGE credit agreement contains a provision requiring BGE to maintain a Debt to Capitalization ratio equal to or less than 65%. As of June 30, 2012, the BGE Debt to Capitalization ratio as defined in its credit agreement was 44%.

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 indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit facility will constitute an event of default under the Exelon corporate credit facilities.

On July 18, 2012, Exelon Corporate, Generation, PECO and BGE launched transactions to amend and extend their unsecured revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million respectively. The amended credit facilities will reflect current market pricing and the extension will bring maturities out to five years from the close of the transactions. The transactions are expected to close and become effective in August 2012. The new covenants are expected to be substantially consistent with existing covenants. Generally, it is expected that costs incurred to amend and extend the facilities will be amortized over the newly extended lives of the facilities. The maturity of the $1.5 billion Constellation Credit Agreement will be amended to December 31, 2012.

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.

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. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the ~~six~~nine months ended ~~June~~September 30, 2012, in addition to the net contribution or borrowing as of ~~June~~September 30, 2012, are presented in the following table:


Contributed (borrowed) as of June 30, 2012	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Contributed (borrowed) as of September 30, 2012								Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Generation	$	—	$	258	$	—		$	—	$	258	$	—
PECO		309		—		64			309		—		77
BSC		—		206		(64	)		—		206		(77	)
Exelon Corporate		44		N/A		—			44		N/A		—

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 regard 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 regard to fixed-income securities, Generation’s investment policy limits the concentrations of the types of bonds that may be purchased for the trust funds and also requires a minimum percentage of the portfolio to have investment grade ratings (minimum credit quality ratings of “Baa3” by Moody’s, “BBB-” by S&P and “BBB-” by Fitch Ratings) while requiring that the overall portfolio maintain a minimum credit quality rating of “A2”. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.

On May 29, 2012, the Registrants filed a combined shelf registration statement unlimited in amount, with the SEC, which became immediately effective. As of ~~June~~September 30, 2012, Exelon, Generation, ComEd, PECO and BGE each had a current shelf registration statement effective with the SEC that provides for the sale of unspecified amounts of ~~securities~~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 Registrant, its securities ratings and market conditions.

On February 27, 2012, ComEd received $1.3 billion in long-term debt refinancing authority from the ICC. As of ~~June~~September 30, 2012, ComEd had $1.4 billion available in long-term debt refinancing authority and $456 million available in new money long-term debt financing authority from the ICC. PECO had ~~$1.9~~$1.6 billion available in long-term debt financing authority from the PAPUC and BGE had ~~$2.0~~$1.8 billion available in long-term financing authority from the MDPSC. On ~~August 1,~~October 24, 2012, ~~PECO filed an~~the PAPUC approved PECO’s application for long-term financing authority ~~with the PAPUC~~ for ~~an amount up to~~ $2.5 billion, which will be effective over a three-year period from January 1, 2013 through December 31, 2015. ~~PECO anticipates receiving the approval from the PAPUC in the fourth quarter of 2012.~~

As of ~~June~~September 30, 2012, ComEd and PECO had short-term financing authority from FERC, which expires on December 31, 2013, of $2.5 billion and $1.5 billion, respectively. BGE had short-term financing authority from FERC, which expires December 31, 2012, of $0.7 billion. On October 26, 2012, BGE filed an application with FERC for renewal of its short-term financing authority through December 31, 2014. BGE expects resolution of the application before the end of the year. Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 16 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ commitments.

Generation, ComEd, PECO and BGE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd, PECO and BGE 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.

For an in-depth discussion of the Registrant’s contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2011 Form 10-K and Constellation’s and BGE’s 2011 Form 10-K.

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 executive officer, chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Risk Oversight Committee of 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’ 2011 Annual Report on Form 10-K incorporated herein by reference.

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.

Normal Operations and Hedging Activities. Electricity available from Generation’s owned, contracted or investments in generation supply in excess of Generation’s obligations to customers, including ComEd’s, PECO’s and BGE’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, including the ComEd financial swap contract, will occur during 2012 through 2014. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 8 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 ~~June~~September 30, 2012, the percentage of expected generation hedged was ~~99%-102%~~98%-101%, ~~79%-82%~~87%-90%, 55%-58% and ~~46%-49%~~20%-23% for 2012, 2013, 2014 and ~~2014,~~2015, 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 excluding owned generation to be retired or sold in 2012. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including sales to ComEd, PECO and BGE 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 around-the-clock energy price based on ~~June~~September 30, 2012 market conditions and hedged position would be a decrease in pre-tax net income of approximately ~~$18~~$10 million, ~~$224~~$110 million and ~~$609~~$500 million, respectively, for 2012, 2013 and ~~2014, including coal units to be divested through September 2012.~~2014. 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.

Proprietary Trading Activities.Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary 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 ~~4,248~~4,352 GWhs and ~~6,077~~9,981 GWhs for the three and ~~six~~nine months ended ~~June~~September 30, 2012, respectively, and ~~1,496~~1,679 GWhs and ~~2,829~~4,508 GWhs for the three and ~~six~~nine months ended ~~June~~September 30, 2011, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the ~~six~~nine months ended ~~June~~September 30, 2012 resulted in pre-tax gains of ~~$11~~$10 million due to net mark-to-market gains of ~~$46~~$69 million and realized losses of ~~$35~~$59 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged ~~$1.6~~$2.9 million during the quarter. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the ~~six~~nine months ended ~~June~~September 30, 2012 of ~~$3,596~~$5,491 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 ~~56%~~57% of Generation’s uranium concentrate requirements from 2012 through 2016 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 16 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd will be entitled to receive full cost recovery in rates. The change in fair value each period is recorded by ComEd with an offset to a regulatory asset or liability. This financial swap contract between Generation and ComEd expires on May 31, 2013.

ComEd’s RFP contracts are deemed to be derivatives that qualify for the normal purchases and normal sales exception under derivative accounting guidance. ComEd does not enter into derivatives for speculative or trading purposes.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. Delivery under these contracts begins in June 2012. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Notes 4 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.

PECO has block contracts and full requirements contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Program, which is further discussed in Note 4 of the Combined Notes to Consolidated Financial Statements. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales exception under current derivative authoritative guidance. Under the DSP Program, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.

PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

PECO does not enter into derivatives for speculative or proprietary trading purposes. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information on these contracts.

BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.

BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.

BGE does not enter into derivatives for speculative or proprietary trading purposes. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information on these contracts.

Trading and Non-Trading Marketing Activities. The following detailed presentation of Exelon’s, Generation’s, ComEd’s and BGE’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 BGE’s mark-to-market net asset or liability balance sheet position from December 31, 2011 to ~~June~~September 30, 2012. 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. See Note 8 of the Combined Notes to the Consolidated Financial Statements 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 ~~June~~September 30, 2012 and December 31, 2011.


	Generation			ComEd			BGE		Intercompany Eliminations(g)			Exelon			Generation			ComEd			BGE		Intercompany Eliminations(g)			Exelon
Total mark-to-market energy contract net assets (liabilities) at December 31, 2011(a)	$	1,648		$	(800	)	$	—	$	—		$	848		$	1,648		$	(800	)	$	—	$	—		$	848
Contracts Acquired at merger date(h)		140											140
Contracts Acquired at merger date (h)																140											140
Total change in fair value during 2012 of contracts recorded in result of operations		163			—			—		15			178			48			—			—		33			81
Reclassification to realized at settlement of contracts recorded in results of operations		148			—			—		—			148			302			—			—		—			302
Ineffective portion recognized in income(b)		(5	)		—			—		—			(5	)		(5	)		—			—		—			(5	)
Reclassification to realized at settlement from accumulated OCI(c)		(722	)		—			—		319			(403	)		(1,005	)		—			—		455			(550	)
Effective portion of changes in fair value — recorded in OCI(d)		719			—			—		(146	)		573			719			—			—		(146	)		573
Changes in fair value — energy derivatives(e)		—			183			—		(188	)		(5	)		—			378			—		(342	)		36
Changes in collateral		(443	)		—			—		—			(443	)		(313	)		—			—		—			(313	)
Changes in net option premium paid/(received)		108			—			—		—			108			122			—			—		—			122
Other income statement reclassifications(f)		(64	)		—			—		—			(64	)		(119	)		—			—		—			(119	)
Intercompany Elimination of Existing Derivative Contracts with Constellation		(103	)		—			—		—			(103	)		(103	)		—			—		—			(103	)
Other balance sheet reclassifications		1			—			—		—			1			(3	)		—			—		—			(3	)

Total mark-to-market energy contract net assets (liabilities) at June 30, 2012(a)	$	1,590		$	(617	)	$	—	$	—		$	973
Total mark-to-market energy contract net assets (liabilities) at September 30, 2012(a)															$	1,431		$	(422	)	$	—	$	—		$	1,009

Fair Values.The following tables 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 7 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.


	Maturities Within																				Maturities Within														Total Fair Value
	2012			2013			2014			2015			2016		2017 and Beyond			Total Fair Value			2012		2013		2014			2015			2016		2017 and Beyond		Total Fair Value
Normal Operations, economic hedge contracts(a)(b):
Actively quoted prices (Level 1)	$	(7	)	$	(11	)	$	(116	)	$	(48	)	$	5	$	2		$	(175	)	$	10	$	2	$	(87	)	$	(41	)	$	11	$	2	$	(103	)
Prices provided by external sources (Level 2)		91			297			334			116			17		(2	)		853			116		317		331			103			21		—		888
Prices based on model or other valuation methods (Level 3)(c)		61			107			72			43			25		(13	)		295			—		76		60			42			23		23		224

Total	$	145		$	393		$	290		$	111		$	47	$	(13	)	$	973		$	126	$	395	$	304		$	104		$	55	$	25	$	1,009


	Maturities Within																				Maturities Within
	2012			2013			2014			2015			2016		2017 and Beyond			Total Fair Value			2012		2013		2014			2015			2016		2017 and Beyond		Total Fair Value
Normal Operations, economic hedge contracts(a)(b) :
Actively quoted prices (Level 1)	$	(7	)	$	(11	)	$	(116	)	$	(48	)	$	5	$	2		$	(175	)	$	10	$	2	$	(87	)	$	(41	)	$	11	$	2	$	(103	)
Prices provided by external sources (Level 2)		91			297			334			116			17		(2	)		853			116		317		331			103			21		—		888
Prices based on model or other valuation methods (Level 3)		367			335			88			57			38		27			912			161		290		76			57			36		26		646

Total	$	451		$	621		$	306		$	125		$	60	$	27		$	1,590		$	287	$	609	$	320		$	119		$	68	$	28	$	1,431

Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd, PECO and BGE)

The Registrants are exposed to credit-related losses in the event of non-performance by counterparties with whom they 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 8 of the Combined Notes to Consolidated Financial Statements for a detail discussion of credit risk, collateral, and contingent related features.

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 ~~June~~September 30, 2012. 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, ICE and the Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of ~~$61~~$53 million, ~~$59~~$53 million and $11 million, respectively. See Note 21 of the Exelon 2011 Form 10-K for further information.


Rating as of June 30, 2012	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
Rating as of September 30, 2012											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	$	2,523	$	802	$	1,721		—	$	—	$	1,968	$	492	$	1,476		—	$	—
Non-investment grade		88		41		47		—		—		46		25		21		—		—
No external ratings
Internally rated — investment grade		552		16		536		1		286		501		16		485		1		267
Internally rated — non-investment grade		64		7		57		—		—		90		2		88		—		—

Total	$	3,227	$	866	$	2,361		1	$	286	$	2,605	$	535	$	2,070		1	$	267


	Maturity of Credit Risk Exposure								Maturity of Credit Risk Exposure
Rating as of June 30, 2012	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Rating as of September 30, 2012									Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,933	$	463	$	127	$	2,523	$	1,472	$	374	$	122	$	1,968
Non-investment grade		64		24		—		88		34		12		—		46
No external ratings
Internally rated — investment grade		335		187		30		552		291		187		23		501
Internally rated — non-investment grade		64		—		—		64		90		—		—		90

Total	$	2,396	$	674	$	157	$	3,227	$	1,887	$	573	$	145	$	2,605


Net Credit Exposure by Type of Counterparty	As of June 30, 2012		As of September 30, 2012
Investor-owned utilities, marketers and power producers	$	1,091	$	902
Energy cooperatives and municipalities		775		710
Financial institutions		406		386
Other		89		72

Total	$	2,361	$	2,070

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 2011 Annual Report on Form 10-K.

See Note 8 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

There have been no significant changes or additions to PECO’s exposures to credit risk as described in ITEM 1A. RISK FACTORS of Exelon’s 2011 Annual Report on Form 10-K.

See Note 8 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

There have been no significant changes or additions to BGE’s exposures to credit risk as described in ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS of BGE’s 2011 Annual Report on Form 10-K.

See Note 8 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the purchase and sale of electricity, fossil fuel and other commodities. 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, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances at the time of the demand. Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure.

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, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements.

As of ~~June~~September 30, 2012, Generation had ~~$697~~$415 million cash collateral deposit payments being held by counterparties and Generation was holding ~~$1,007~~$607 million of cash collateral deposits received from counterparties, of which ~~$323~~$193 million in net cash collateral deposits was offset against mark-to-market assets and liabilities. As

of ~~June~~September 30, 2012, ~~$13~~$1 million of cash collateral ~~received~~posted was not offset against net derivative positions because it was not associated with energy-related derivatives. See Note 16 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

As of ~~June~~September 30, 2012, ComEd held immaterial amounts of cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts and held approximately ~~$20~~$19 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts.

As of ~~June~~September 30, 2012, PECO was not required to post, nor does it hold, collateral under its energy supply and natural gas procurement contracts. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

BGE is not required to post collateral under its electric supply contracts. As of ~~June~~September 30, 2012, BGE was not required to post collateral under its natural gas procurement contracts, nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

Generation, ComEd, PECO and BGE participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, New York ISO, California ISO, MISO, Southwest Power Pool, Inc., AESO, OIESO and ERCOT. 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.

Generation enters into commodity transactions on NYMEX, ICE and the Nodal exchange. The NYMEX, ICE and the Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on NYMEX, ICE and the Nodal exchange must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and the Nodal exchange are significantly collateralized and have limited counterparty credit risk.

Exelon’s consolidated balance sheets, as of ~~June~~September 30, 2012, included a ~~$670~~$678 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 ~~$822~~$814 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.

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. 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 manage interest rate risk. At ~~June~~September 30, 2012, Exelon had $800 million of notional amounts of fixed-to-floating interest rate swaps outstanding, of which $650 million are designated as fair value hedges and $150 million are marked to market. Generation had ~~$463~~$396 million of notional amounts of cash flow hedges outstanding. Assuming the fair value and cash flow hedges are effective, a hypothetical 50 bps increase in the interest rates associated with variable-rate debt and interest rate swaps would result in ~~less than a~~approximately $ 2 million decrease in ~~each of Exelon’s, Generation’s and PECO’s~~Exelon Consolidated pre-tax ~~earnings~~income for the ~~six~~nine months ended ~~June~~September 30, 2012. This calculation holds all other variables constant and assumes only the discussed changes in interest rates.

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of ~~June~~September 30, 2012, 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 ~~$353~~$382 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.

During the ~~second~~third quarter of 2012, each of Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’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 all

Registrants to ensure that (a) material information relating to that Registrant, 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 that Registrant and its subsidiaries as appropriate to allow

timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of ~~June~~September 30, 2012, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO and BGE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the ~~second~~third quarter of 2012 ~~other than changes resulting from the Constellation merger and BGE’s implementation of the Customer Care and Billing (CC&B) system as discussed below,~~ that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s internal control over financial reporting.

On March 12, 2012, the merger between Exelon and Constellation closed. Exelon is currently in the process of integrating Constellation’s operations, processes, and internal controls. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information regarding the merger.

~~On January 3, 2012, BGE completed implementation of its new CC&B system that is now being utilized to bill all gas and electric customers within the BGE service territory.~~

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’ 2011 Form 10-K and (b) Notes 3, 4 and 16 of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

Exclusive of theRisks Related to the Pending Merger with Constellation described in Exelon’s 2011 Form 10-K in ITEM 1A. RISK FACTORS, Exelon is, and will continue to be, subject to the risks described in Exelon’s and Constellation’s 2011 Form 10-K in (a) ITEM 1A. RISK FACTORS, (b) ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and (c) ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA: Note 18 of the Combined Notes to Consolidated Financial Statements in Exelon’s 2011 Form 10-K and Note 12 of the Notes to Consolidated Financial Statements in Constellation’s 2011 Form 10-K. As a result of the merger with Constellation that closed on March 12, 2012 Exelon is subject to additional risks related to the merger as described below.

The merger may not achieve its anticipated results, and Exelon may be unable to integrate the operations of Constellation in the manner expected.

Exelon and Constellation entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation can be integrated in an efficient, effective and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect Exelon’s future business, financial condition, operating results and prospects.

The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.

Exelon currently anticipates that the merger will be accretive to earnings per share in 2013, which will be the first full year following completion of the merger. This expectation is based on preliminary estimates that are subject to change. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.

The merger may adversely affect Exelon’s ability to attract and retain key employees.

Current and prospective Exelon employees may experience uncertainty about their future roles at Exelon as a result of the merger. In addition, current and prospective Exelon employees and former Constellation employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect Exelon’s ability to attract and retain key management and other personnel.

Exelon may incur unexpected transaction fees and merger-related costs in connection with the merger.

Exelon expects to incur a number of non-recurring expenses associated with completing the merger, as well as expenses related to combining the operations of the two companies. Exelon may incur additional unanticipated costs in the integration of the businesses of Exelon and Constellation. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.

Exelon may encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the Constellation merger.

As a result of the process to obtain regulatory approvals required for the Constellation merger, Exelon is committed to various programs, contributions, investments and market mitigation measures in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays, unexpected difficulties or costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2012 filed by the following officers for the following companies:

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~June~~September 30, 2012 filed by the following officers for the following companies:

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.


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

1-1910	BALTIMORE GAS AND ELECTRIC COMPANY		52-0280210
	(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000


Exelon Corporation Common Stock, without par value		~~853,573,260~~854,283,102
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		~~127,016,620~~127,061,710
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company Common Stock, without par value		1,000


		Page No.

	7. Fair Value of Financial Assets and Liabilities		5558

	8. Derivative Financial Instruments		7881

	9. Debt and Credit Agreements		9598

	10. Income Taxes		99104

	11. Nuclear Decommissioning		~~103~~107

	12. Retirement Benefits		~~106~~111

	13. Plant Retirements		~~109~~114

	14. Stock-Based Compensation Plans		~~110~~115

	15. Earnings Per Share and Equity		~~115~~120

	16. Commitments and Contingencies		~~115~~120

	17. Supplemental Financial Information		~~131~~137

	18. Segment Information		~~137~~142

	19. Subsequent Events		147

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		~~144~~148

	Exelon Corporation		~~144~~148

	General		~~144~~148

	Executive Overview		~~145~~149

	Critical Accounting Policies and Estimates		~~162~~167

	Results of Operations		~~162~~168

	Liquidity and Capital Resources		~~191~~198

	Contractual Obligations and Off-Balance Sheet Arrangements		~~204~~211

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~205~~212

ITEM 4.	CONTROLS AND PROCEDURES		~~213~~220

PART II.	OTHER INFORMATION		~~215~~222

ITEM 1.	LEGAL PROCEEDINGS		~~215~~222

ITEM 1A.	RISK FACTORS		~~215~~222

ITEM 4.	MINE SAFETY DISCLOSURES		~~216~~223

ITEM 6.	EXHIBITS		~~216~~223

SIGNATURES			~~218~~225

	Exelon Corporation		~~218~~225

	Exelon Generation Company, LLC		~~218~~225

	Commonwealth Edison Company		~~218~~225

	PECO Energy Company		~~219~~226

	Baltimore Gas and Electric Company		~~219~~226

CERTIFICATION EXHIBITS			~~220~~227

	Exelon Corporation		~~220, 230~~227,237

	Exelon Generation Company, LLC		~~222, 232~~229, 239

	Commonwealth Edison Company		~~224, 234~~231, 241

	PECO Energy Company		~~226, 236~~233, 243

	Baltimore Gas and Electric Company		~~228, 238~~235, 245


	Number of Shares/ Awards Issued		Total Fair Value
Issuance of Exelon common stock to Constellation shareholders and equity award holders at the exchange ratio of 0.930 shares for each share of Constellation common stock; based on the opening price of Exelon common stock on March 12, 2012 of $38.91(a)		187.45	$	7,294
Issuance of Exelon equity awards to replace existing Constellation equity awards(b)		11.30		71

Total purchase price			$	7,365


		Page No.

FILING FORMAT			6

FORWARD-LOOKING STATEMENTS			6

WHERE TO FIND MORE INFORMATION			6

PART I.	FINANCIAL INFORMATION		7

ITEM 1.	FINANCIAL STATEMENTS		7

	Exelon Corporation

	Consolidated Statements of Operations and Comprehensive Income		8

	Consolidated Statements of Cash Flows		9

	Consolidated Balance Sheets		10

	Consolidated Statement of Changes in Shareholders’ Equity		12

	Exelon Generation Company, LLC

	Consolidated Statements of Operations and Comprehensive Income		13

	Consolidated Statements of Cash Flows		14

	Consolidated Balance Sheets		15

	Consolidated Statement of Changes in Equity		17

	Commonwealth Edison Company

	Consolidated Statements of Operations and Comprehensive Income		18

	Consolidated Statements of Cash Flows		19

	Consolidated Balance Sheets		20

	Consolidated Statement of Changes in Shareholders’ Equity		22

	PECO Energy Company

	Consolidated Statements of Operations and Comprehensive Income		23

	Consolidated Statements of Cash Flows		24

	Consolidated Balance Sheets		25

	Consolidated Statement of Changes in Shareholders’ Equity		27

	Baltimore Gas and Electric Company

	Consolidated Statements of Operations and Comprehensive Income		28

	Consolidated Statements of Cash Flows		29

	Consolidated Balance Sheets		30

	Consolidated Statement of Changes in Shareholders’ Equity		32

	Combined Notes to Consolidated Financial Statements		33

	1. Basis of Presentation		33

	2. New Accounting Pronouncements		36

	3. Merger and Acquisitions		36

	4. Regulatory Matters		4445

	5. Investment in Constellation Energy Nuclear Group, LLC		5356

	6. Goodwill		5457


	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income, net			Noncontrolling Interest			Total Equity
Balance, December 31, 2011	$	3,556	$	4,232		$	915		$	5		$	8,708
Net income		—		334			—			(2	)		332
Acquisition of Constellation		5,272		—			—			—			5,272
Noncontrolling interest acquired		—		—			—			95			95
Distribution to member		—		(891	)		—			—			(891	)
Other comprehensive loss, net of income taxes of $4		—		—			(11	)		—			(11	)

Balance, June 30, 2012	$	8,828	$	3,675		$	904		$	98		$	13,505


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive Loss, net			Total Shareholders’ Equity
Balance, December 31, 2011	$	1,588	$	5,003	$	(1,639	)	$	2,086		$	(1	)	$	7,037
Net income		—		—		129			—			—			129
Appropriation of retained earnings for future dividends		—		—		(129	)		129			—			—
Common stock dividends		—		—		—			(85	)		—			(85	)
Allocation of tax benefit from parent		—		13		—			—			—			13
Other comprehensive income, net of income taxes of $0		—		—		—			—			1			1

Balance, June 30, 2012	$	1,588	$	5,016	$	(1,639	)	$	2,130		$	—		$	7,095


Severance Benefits(a)	Exelon		Generation		ComEd(b)		PECO		BGE(c)
Expense recorded — three months	$	36	$	25	$	5	$	2	$	2
Expense recorded — six months		119		70		16		7		18


	Three Months Ended June 30, 2012			For the Period March 12, through June 30, 2012
CENG	$	4		$	(5	)
Amortization of basis difference in CENG		(62	)		(74	)

Total equity investment income (loss) — CENG	$	(58	)	$	(79	)


	Three Months Ended September 30, 2012			For the Period March 12, through September 30, 2012
Equity investment income	$	58		$	53
Amortization of basis difference in CENG		(57	)		(131	)

Total equity in earnings (losses) — CENG	$	1		$	(78	)


	Increase/(Decrease) in Earnings			Increase/(Decrease) in Earnings			Income Statement Classification	Accounts Receivable/ (Accounts Payable) At June 30, 2012
Agreement	Three Months Ended June 30, 2012			For the Period March 12 through June 30, 2012			Income Statement Classification	Accounts Receivable/ (Accounts Payable) At June 30, 2012
PPA	$	(216	)	$	(251	)	Purchased power and fuel	$	(90	)
PSAA(a)		3			4		Operating revenues		—
ASA		12			15		Operating expenses		4


	Income/(Expense)			Income/(Expense)			Income Statement Classification	Accounts Receivable/ (Accounts Payable) At September 30, 2012
Agreement	Three Months Ended September 30, 2012			For the Period March 12 through September 30, 2012			Income Statement Classification
PPA	$	(282	)	$	(541	)	Purchased power and fuel	$	(86	)
PSAA		1			2		Operating revenues		—
SSA		14			30		Operating revenues		5


	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the three months ended June 30, 2012	$	(96	)	$	29
Total gains (losses) included in income for the six months ended June 30, 2012	$	(9	)	$	27
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2012	$	(22	)	$	21
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2012	$	93		$	10


	Operating Revenue		Purchased Power and Fuel
Total gains included in income for the three months ended June 30, 2011	$	10	$	11
Total gains (losses) included in income for the six months ended June 30, 2011	$	7	$	1
Change in the unrealized gains relating to assets and liabilities held for the three months ended June 30, 2011	$	17	$	13
Change in the unrealized gains relating to assets and liabilities for the six months ended June 30, 2011	$	21	$	2


	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the three months ended June 30, 2012	$	(101	)	$	30
Total gains (losses) included in income for the six months ended June 30, 2012	$	(25	)	$	28
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2012	$	(36	)	$	21
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2012	$	68		$	10


Type of trade	Fair Value at June 30, 2012			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Generation)(a)	$	514		Discounted Cash Flow	Forward power price		$9 - $67
					Forward gas price		$2.75 - $7.46
				Option Model	Volatility percentage		25% - 304%

Mark-to-market derivatives — Proprietary trading (Generation)(a)	$	(115)		Discounted Cash Flow	Forward power price		$15 - $75
				Option Model	Volatility percentage		22% - 59%

Mark-to-market derivatives — Transactions with affiliates (Generation and ComEd)(b)	$	506		Discounted Cash Flow	Marketability reserve		7.9% - 9.5%
				Discounted Cash Flow	Forward heat rate(c)		8.0% - 9.5%

Mark-to-market derivatives (ComEd)	$	(111	)		Marketability reserve		3.5% - 8.3%
					Renewable factor		88% - 125%


Type of trade	Fair Value at September 30, 2012(d)			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Generation)(a)	$	386		Discounted Cash Flow	Forward power price	$8 - $76
					Forward gas price	$3.04 - $6.35
				Option Model	Volatility percentage	26% - 120%

Mark-to-market derivatives — Proprietary trading (Generation)(a)	$	(83	)	Discounted Cash Flow	Forward power price	$13 - $108
				Option Model	Volatility percentage	22% - 67%

Mark-to-market derivatives — Transactions with affiliates (Generation and ComEd) (b)	$	352		Discounted Cash Flow	Marketability reserve	7.3% - 8.7%

Mark-to-market derivatives (ComEd)	$	(70	)	Discounted Cash Flow	Forward heat rate (c)	8.5% - 9.5%
					Marketability reserve	3.5% - 8.3%
					Renewable factor	80% - 126%


Commercial Paper Borrowings	September 30, 2012		December 31, 2011
Exelon Corporate	$	15	$	161
Generation		—		—
ComEd		35		—
PECO		—		—
BGE		—		—


Company	Type	Interest Rate			Maturity	Amount		Use of Proceeds
Generation	Senior Notes		4.250	%	June 15, 2022	$	523	Used for general corporate purposes and issued in connection with the Exchange Offer

Generation	Senior Notes		5.600	%	June 15, 2042	$	788	Used for general corporate purposes and issued in connection with the Exchange Offer

Generation	CEU Credit Agreement		1.990	%	June 16, 2016	$	43	Used to fund Upstream gas activities

Generation	DOE Project Financing		2.330 - 3.092%		January 5, 2037	$	100	Funding for Antelope Valley solar development

Generation	Clean Horizons		2.500	%	June 7, 2030	$	38	Funding for Maryland solar development

BGE	Notes		2.800	%	August 15, 2022	$	250	Used to repay total outstanding commercial paper and for general corporate purposes

PECO	First and Refunding Mortgage Bonds		2.375	%	September 15, 2022	$	350	Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes


	Three Months Ended June 30,
$/MWh	2012(a)		2011			% Change
Mid-Atlantic(b)	$	40.68	$	58.79			(30.8	%)
Midwest(c)		31.00		37.28			(16.8	%)
New England		9.01		n.m.			n.m.
New York		13.84		n.m.			n.m.
ERCOT		13.43		(6.52	)		n.m.
Other Regions(d)		4.28		3.08			39.0	%
Electric revenue net of purchased power and fuel expense per MWh(e)(f)		26.15		41.59			(37.1	%)


	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	Increase (Decrease)			Increase (Decrease)
Regulatory required programs	$	23		$	41
Weather — delivery		18			1
Pricing (rate cases)		15			47
Revenues subject to refund, net		14			39
Transmission		7			16
Volume — delivery		(7	)		(6	)
Uncollectible accounts recovery, net		(11	)		(10	)
Reversal of revenue subject to refund		(17	)		(17	)
Discrete impacts of the 2012 Distribution Rate Case Order		(100	)		(88	)
Other		24			34

Total increase (decrease)	$	(34	)	$	57


	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
	Increase (Decrease)			Increase (Decrease)
Transmission	$	7		$	23
Volume — delivery		2			(4	)
Weather — delivery		—			—
Discrete impacts of the 2012 Distribution Rate Case Order		—			(88	)
Revenues subject to refund, net		(17	)		5
Electric distribution rates		(20	)		48
Regulatory required programs		(25	)		17
Other		7			9

Total increase (decrease)	$	(46	)	$	10



	Three Months Ended June 30,				% Change			Six Months Ended June 30,				% Change
Electric Revenue	2012		2011		% Change			2012		2011		% Change
Retail Delivery and Sales(a)
Residential	$	720	$	800		(10.0	)%	$	1,496	$	1,634		(8.4	)%
Small commercial & industrial		306		386		(20.7	)%		654		767		(14.7	)%
Large commercial & industrial		94		95		(1.1	)%		194		186		4.3	%
Public authorities & electric railroads		9		12		(25.0	)%		21		26		(19.2	)%

Total Retail		1,129		1,293		(12.7	)%		2,365		2,613		(9.5	)%

Other Revenue(b)		152		151		0.7	%		305		297		2.7	%

Total Electric Revenues	$	1,281	$	1,444		(11.3	)%	$	2,670	$	2,910		(8.2	)%


Commercial Paper Programs

Commercial Paper Issuer	Maximum Program Size(a)		Outstanding Commercial Paper at June 30, 2012		Average Interest Rate on Commercial Paper Borrowings for the six months ended June 30, 2012
Exelon Corporate(b)	$	500	$	188		0.44	%
Generation		5,600		—		0.45	%
ComEd		1,000		178		0.51	%
PECO		600		—		—
BGE		600		—		—


Commercial Paper Issuer	Maximum Program Size		Outstanding Commercial Paper at September 30, 2012		Average Interest Rate on Commercial Paper Borrowings for the nine months ended September 30, 2012
Commercial Paper Issuer	Maximum Program Size		Outstanding Commercial Paper at September 30, 2012
Exelon Corporate(a)	$	500	$	15		0.47	%
Generation		5,600		—		0.45	%
ComEd		1,000		35		0.50	%
PECO		600		—		—
BGE		400		—		0.43	%


Credit Agreements

								Available Capacity at June 30, 2012				Average Interest Rate on Facility Borrowings for the Six Months Ended June 30, 2012
Borrower	Facility Type	Aggregate Bank Commitment(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper
Exelon Corporate(b)	Syndicated Revolver	$	2,000	$	—	$	43	$	1,957	$	498		—
Exelon Corporate(b)	Bilateral / Commodity Linked		900		—		573		327		—		—
Generation	Syndicated Revolver		5,300		—		1,455		3,845		3,845		—
Generation	Bilateral		300		—		299		1		1		—
ComEd	Syndicated Revolver		1,000		—		1		999		821		—
PECO	Syndicated Revolver		600		—		1		599		599		—
BGE	Syndicated Revolver		600		—		1		599		599		—


Exhibit No.		Description
~~4-1~~2.1		Purchase Agreement dated as of August 8, 2012 by and between Constellation Power Source Generation, Inc. and Raven Power Holdings, LLC

4.1		Form of ~~4.25%~~2.80% Senior Note due 2022. (File ~~333-85496,~~1-1910, Form 8-K dated ~~June 18,~~August 17, 2012, Exhibit 4.1)

~~4-2~~4.2		~~Form~~Supplemental Indenture dated as of ~~5.60% Senior Note due 2042.~~September 10, 2012 from PECO Energy Company to BNP Paribas Securities, J.P. Morgan Securities LLC and U.S. Bancorp Investments, Inc., as representatives of the several underwriters named therein. (File ~~333-85496,~~No. 000-16844, Form 8-K dated ~~June 18,~~September 17, 2012, Exhibit ~~4.2)~~4-1)

4.3		Supplemental Indenture dated as of September 17, 2012 from Commonwealth Edison Company to BNY Mellon Trust Company of Illinois, as trustee, and D.G. Donovan, as co-trustee. (File No. 1-1839, Form 8-K dated October 1, 2012, Exhibit 4-1)

101.INS*		XBRL Instance

101.SCH*		XBRL Taxonomy Extension Schema

101.CAL*		XBRL Taxonomy Extension Calculation

101.DEF*		XBRL Taxonomy Extension Definition

101.LAB*		XBRL Taxonomy Extension Labels

101.PRE*		XBRL Taxonomy Extension Presentation


31-1		— Filed by Christopher M. Crane for Exelon Corporation

31-2		— Filed by Jonathan W. Thayer for Exelon Corporation

31-3		— Filed by Christopher M. Crane for Exelon Generation Company, LLC

31-4		— Filed by Andrew L. Good for Exelon Generation Company, LLC

31-5		— Filed by Anne R. Pramaggiore for Commonwealth Edison Company

31-6		— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

31-7		— Filed by Craig L. Adams for PECO Energy Company

31-8		— Filed by Phillip S. Barnett for PECO Energy Company

31-9		— Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company

31-10		— Filed by Carim V. Khouzami for Baltimore Gas and Electric Company


32-1		— Filed by Christopher M. Crane for Exelon Corporation

32-2		— Filed by Jonathan W. Thayer for Exelon Corporation

32-3		— Filed by Christopher M. Crane for Exelon Generation Company, LLC

32-4		— Filed by Andrew L. Good for Exelon Generation Company, LLC

32-5		— Filed by Anne R. Pramaggiore for Commonwealth Edison Company

32-6		— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

32-7		— Filed by Craig L. Adams for PECO Energy Company

32-8		— Filed by Phillip S. Barnett for PECO Energy Company

32-9		— Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company

32-10		— Filed by Carim V. Khouzami for Baltimore Gas and Electric Company


/s/ CHRISTOPHER M. CRANE		/s/ JONATHAN W. THAYER
Christopher M. Crane		Jonathan W. Thayer
President and Chief Executive Officer (Principal Executive Officer)		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ �� DUANE M. DESPARTE
Duane M. DesParte
Vice President and Corporate Controller (Principal Accounting Officer)


/s/ CHRISTOPHER M. CRANE		/s/ ANDREW L. GOOD
Christopher M. Crane		Andrew L. Good
President (Principal Executive Officer)		Chief Financial Officer (Principal Financial Officer)

/s/ ROBERT M. AIKEN
Robert M. Aiken
Chief Accounting Officer
(Principal Accounting Officer)


/s/ ANNE R. PRAMAGGIORE		/s/ JOSEPH R. TRPIK, JR.
Anne R. Pramaggiore		Joseph R. Trpik, Jr.
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ KEVIN J. WADEN
Kevin J. Waden
Vice President and Controller (Principal Accounting Officer)


/s/ CRAIG L. ADAMS		/s/ PHILLIP S. BARNETT
Craig L. Adams		Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ SCOTT A. BAILEY
Scott A. Bailey
Vice President and Controller (Principal Accounting Officer)


/s/ KENNETH W. DEFONTES JR.		/s/ CARIM V. KHOUZAMI
Kenneth W. DeFontes, Jr.		Carim V. Khouzami
President and Chief Executive Officer (Principal Executive Officer)		Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ DAVID M. VAHOS
David M. Vahos
Vice President and Controller (Principal Accounting Officer)