EXELON GENERATION CO LLC - FORM 8-K - EX-99.1 - 2011 FACT BOOK

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8-K - FORM 8-K - EXELON GENERATION CO LLC	d414080d8k.htm

Exhibit 99.1

LOGO


Introduction			1

Exelon at a Glance
Profile, Vision and Quick Facts			2

Company Overview			3

Service Area and Generation Fuel Mix
Map of Exelon Service Area and Selected Generating Assets and 2011 Generation Fuel Mix for Exelon & Constellation			4

Generation Capacity			5

Credit and Liquidity for Exelon and Operating Companies
Credit Ratings, Credit Facilities and Commercial Paper			6

Long Term Debt Outstanding as of June 30, 2012
Exelon Corporation			7
Exelon Generation			7
ComEd			8
PECO			9
BGE			10

Federal Regulation
Federal Energy Regulatory Commission (FERC), ComEd Electric Transmission Rate Cases, BGE Electric Transmission Rate Cases			11

State Regulation
Illinois Commerce Commission (ICC), ComEd Electric Distribution Rate Cases and Average Residential Rate			12
Pennsylvania Public Utility Commission (PUC), PECO Electric and Gas Rate Cases and Average Residential Rate			13
Maryland Public Service Commission (PSC), BGE Electric and Gas Distribution Rate Cases and Average Residential Rate			14

Capital Structure and Capitalization Ratios for Exelon and Operating Companies			15
Financial and Operating Highlights for Exelon in 2011			16
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP
Consolidated Statements of Operations
Exelon Corporation			17
Exelon Generation			18
ComEd			19
PECO			20

Supply and Sales Statistics
Exelon Generation – Annual Electric Supply and Sales Statistics and Financial Swap Agreement with ComEd			21
Exelon Generation – Electric Supply and Sales by Quarter			22
ComEd Electric Sales Statistics, Revenue, and Customer Detail			23
PECO Electric Sales Statistics, Revenue, and Customer Detail			24
PECO Gas Sales Statistics, Revenue, and Customer Detail			25

Exelon Generation – Generating Resources
Total Owned Generating Capacity			26-27
Exelon Nuclear Fleet and Nuclear Operating Data			28-29
Fossil Emissions and Emission Reduction Technology Summary			30-31

Constellation Energy – Generating Resources
Total Owned Generating Capacity			32-33
Constellation Energy Nuclear Group (CENG) Fleet and Nuclear Operating Data			34-35
Fossil Emissions and Emission Reduction Technology Summary			36-39

To the Financial Community,

The Exelon Fact Book is intended to provide historical financial and operating information to assist in the analysis of Exelon and its operating companies. On March 12, 2012, Exelon and Constellation completed the merger of the two companies. On pages 2 through 13 (section 1), we present a snapshot of the business of Exelon Corporation after the close of the merger. The remainder of the book (sections 2 and 3) presents information in its historical form prior to the completion of the merger. Please refer to the SEC filings of Exelon and its subsidiaries, including the annual Form 10-K and quarterly Form 10-Q, of Exelon and its subsidiaries for more comprehensive financial statements and information.

For more information about Exelon and to send e-mail inquiries, visit our website at www.exeloncorp.com.


Investor Information		Stock Symbol: EXC
Exelon Corporation		Common stock is listed on the
Investor Relations		New York and Chicago stock exchanges.
10 South Dearborn Street
Chicago, IL 60603
312.394.2345
312.394.8941 (fax)

Information in this Fact Book is current as of July 31, 2012 unless otherwise noted.

This publication contains certain 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 Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2011 Annual Report on 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; (2) Constellation Energy Group’s 2011 Annual Report on 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 12; (3) the Registrant’s Second Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 16; and (4) other factors discussed in 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 publication. 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 publication.

Exelon at a Glance

Company Profile

Headquartered in Chicago, Exelon a leading competitive energy provider, with operations and business activities in 47 states, the District of Columbia and Canada. The company is the largest competitive U.S. power generator, with approximately 35,000^(a) megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. Constellation, Exelon’s competitive retail and wholesale energy business, provides energy products and services to approximately 100,000 business and public sector customers and approximately 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

Our Vision: Performance that drives progress

At Exelon, we believe that our high-performance energy is the engine of progress. Our commitment to excellence in everything we do means that we are driven to learn and grow, challenging ourselves to constantly adapt, enhance and advance. Every day we focus on maximizing the potential of energy. Safely. Reliably. Sustainably. We vigorously compete to give our customers greater choice and value, and drive innovations that help businesses function more effectively and help people live better. Our end-to-end perspective across the energy business, coupled with our ingenuity and commitment, gives us the insight to seize the opportunities of today, while maintaining the focus and long-term view to tackle the challenges of tomorrow. We make energy work harder because we believe that clean, affordable energy is the key to a brighter, more sustainable future – where our customers succeed, our communities thrive and our nation prospers.

Our Values

We are dedicated to safety.

We actively pursue excellence.

We innovate to better serve our customers.

We act with integrity and are accountable to our communities and the environment.

We succeed as an inclusive and diverse team.

Quick Facts: Exelon and Constellation Combined for 2011

$32.7

billion in operating revenues

$74.5

billion in assets

6.6

million electric customers

1.2

million gas customers

~27,000

employees

7,350

circuit miles of electric transmission lines

~35,000

MW U.S. generating capacity

164

terawatt-hours of electric load served

372

billion cubic feet of natural gas load served

$2.10

current annual dividend rate per share^(b)

(a)	Excludes Maryland coal assets divested in 2012.

(b)	Represents Exelon’s annual dividend both before and after the Constellation merger. Dividends are subject to declaration by the board of directors each quarter.

Company Overview

LOGO




Energy Generation	Competitive Energy Sales	Transmission & Delivery
Exelon Generation is the No. 1 competitive power generator in the nation, with owned generating assets totaling approximately 35,000^(a)megawatts. With strong positions in the Midwest, Mid-Atlantic, Texas and California, Exelon is the largest owner and operator of nuclear plants in the United States and maintains a growing renewable energy development business headquartered in Baltimore.	Constellation, headquartered in Baltimore, is a leading competitive wholesale and retail supplier of power, natural gas and energy products and services for homes and businesses across the continental United States and in the Canadian provinces of Alberta, British Columbia and Ontario. Constellation’s retail business serves more than 100,000 business and public sector customers, including more than two-thirds of the Fortune 100, and approximately 1 million residential customers. The company is among the market leaders in commercial solar installations, as well as energy efficiency and load response products and services.	Exelon’s delivery companies – BGE, ComEd, and PECO – work hard to keep the lights on and the gas flowing for approximately 6.6 million customers. Baltimore Gas and Electric Company (BGE) is a regulated electricity transmission and distribution company and natural gas distribution company with a combined service area encompassing Baltimore City and all or part of 10 central Maryland counties. BGE serves approximately 1.2 million electric customers in a 2,300-square-mile territory and approximately 650,000 natural gas customers in an 800-square-mile territory. Commonwealth Edison Company (ComEd) is a regulated electricity transmission and delivery company with a service area in northern Illinois, including the City of Chicago, of approximately 11,400 square miles and an estimated population of 9.3 million. ComEd has approximately 3.8 million customers. PECO Energy Company (PECO) is a regulated electricity transmission and distribution company and natural gas distribution company with a combined service area in southeastern Pennsylvania, including the City of Philadelphia, of approximately 2,100 square miles and an estimated population of 4.0 million. PECO has approximately 1.6 million electric customers and 490,000 natural gas customers.
Our Goals
• Keep the lights on and the gas flowing
• Run the generation fleet at world class levels
• Foster a work environment that is safe, productive, learning-focused and engaging
• Capitalize on clean energy as a competitive advantage
• Build sustained value through disciplined financial management
• Be a top-tier competitor in our key markets
• Advance competitive markets
(a) Excludes Maryland coal assets divested in 2012.

Exelon Service Area and Generation Fuel Mix

Exelon Service Area and Selected Generation Assets as of June 30, 2012

LOGO

2011 Generation Fuel Mix

Exelon & Constellation – Ownership Equity


Capacity (MW)	Exelon			Constellation
Nuclear		67	%		16	%
Coal		3	%		23	% ^(a)
Oil		8	%		6	%
Gas		13	%		50	%
Hydro & Renewables		10	%		5	%


Output (MWh)	Exelon			Constellation
Nuclear		92	%		30	%
Coal		3	%		24	% ^(a)
Oil		<1	%		0	%
Gas		1	%		41	%
Hydro & Renewables		3	%		5	%

Note: Percentages may not add due to rounding

(a)	Includes Maryland coal assets divested in 2012.

LOGO

*	Legacy Constellation generating assets divested in 2012 for market power mitigation purposes.

Generation Capacity

Owned Generation (in MWs) as of December 31, 2011^(a)


	Exelon		Constellation		Total
Nuclear^(b)		17,115		1,925		19,040
Fossil		5,890		9,351		15,241
Renewables		2,539		475		3,014

Total Owned Generation		25,544		11,751		37,295

Contracted Generation (in MWs) as of December 31, 2011^(a)


	2012		2013		2014
ERCOT
Oil/Gas		1,052		1,052		885
Renewables		203		203		203

Total		1,255		1,255		1,088

Mid-Atlantic
Nuclear^(c)		725		435		218
Oil/Gas		695		695		695
Renewables		208		176		176

Total		1,628		1,306		1,089

Midwest
Coal		1,158		1,158		—
Oil/Gas		1,932		1,157		1,157
Renewables		814		666		612

Total		3,904		2,981		1,769

NEPOOL
Oil/Gas		620		620		620
Renewables		41		17		17

Total		661		637		637

New York
Nuclear^(c)		882		314		107
Renewables		27		27		—

Total		909		342		107

South/West/Canada
Oil/Gas		3,184		3,184		3,184
Renewables		153		153		153

Total		3,337		3,337		3,337

Total Contracted Generation		11,694		9,858		8,027

(a)	Represents owned and contracted generation capacity for legacy Exelon and legacy Constellation as of 12/31/11.

(b)	Owned generating capacity figures reflect Constellation’s 50.01% equity interest in Constellation Energy Nuclear Group (CENG), which owns and operates the Calvert Cliffs, Nine Mile Point, and R.E. Ginna nuclear generating stations.

(c)	Constellation has a PPA under which it purchases 85% of the total output of the CENG plants; consequently a ratable view of the 85% of the un-owned portion of total capacity is listed as contracted capacity.

Credit and Liquidity for Exelon and Operating Companies

Credit Ratings as of June 30, 2012

Moody’s Investors
Service^(a)

Standard & Poor’s
Corporation^(b)

Fitch Ratings^(b)

Exelon Corporation

Senior Unsecured Debt

Baa2

^(c)

BBB-

BBB+

Commercial Paper

^(c)

Exelon Generation

Senior Unsecured Debt

Baa1

^(c)

BBB

BBB+

Commercial Paper

BGE

Senior Secured Debt

N/A

A-

Senior Unsecured Debt

Baa1

BBB+

Commercial Paper

ComEd

Senior Secured Debt

A-

BBB+

Senior Unsecured Debt

Baa2

BBB

Commercial Paper

PECO

Senior Secured Debt

A-

Senior Unsecured Debt

N/A

A-

Commercial Paper

(a)	Moody’s downgraded Exelon and Exelon Generation and upgraded BGE upon completion of the merger with Constellation Energy. Exelon and Generation were also placed on negative outlook.

(b)	S&P and Fitch affirmed ratings of Exelon and all subsidiaries upon completion of the merger.

(c)	On June 11, 2012, Moody’s placed Exelon’s short-term and long-term ratings and Generation’s long-term ratings under review for downgrade. All other ratings are stable.

Credit Facilities and Commercial Paper as of June 30, 2012


	BG&E			ComEd			PECO			Generation			Exelon Corporate			Total
(in millions)
Unsecured Revolving Credit Facilities^(a)	$	600		$	1,000		$	600		$	5,600		$	2,900	^(c)	$	10,700
Outstanding Facility Draws		—			—			—			—			—			—
Outstanding Letters of Credit		(1	)		(1	)		(1	)		(1,754	)		(616	)		(2,373	)

Available Capacity under Facilities^(b)		599			999			599			3,846			2,284			8,327
Outstanding Commercial Paper		—			(178	)		—			—			(188	)		(366	)

Available Capacity less Outstanding Comm. Paper	$	599		$	821		$	599		$	3,846		$	2,096		$	7,961

(a)	Equals aggregate bank commitments under revolving credit agreements. Excludes commitments from Exelon’s Community and Minority Bank Credit Facility.

(b)	Represents unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and credit facility draws. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(c)

Includes Exelon Corporate’s $500M credit facility and Legacy Constellation credit facilities assumed as part of the merger as well as letters of credit and commercial paper outstanding. Exelon will be unwinding approximately $4 billion in credit facilities assumed from legacy Constellation over the course of this year.

Long-Term Debt Outstanding as of June 30, 2012

Exelon Corporation


Series	Interest Rate			Date Issued		Maturity Date		Total Debt Outstanding		Current Portion		Long-Term Debt
(in millions)
Senior Notes Payable
2005 Senior Notes Payable		4.90	%		6/9/05		6/15/15	$	800	$	—	$	800
2005 Senior Notes		5.625	%		6/9/05		6/15/35		500		—		500

Total Senior Notes Payable								$	1,300	$	—	$	1,300

Unamortized Debt Disc. & Prem. & Fair Value Ammortization, Net									4		—		4
BGE Debt Fair Value Adjustment^(a)									293		—		293

Total Long-Term Debt								$	1,597	$	—	$	1,597


Maturities		2012			2013		2014		2015		2016
		—			—		—	$	800		—

(a)	This adjustment is held at Exelon per the determination to not apply push-down accounting to BGE.

Exelon Generation


Series	Interest Rate			Date Issued		Maturity Date		Total Debt Outstanding			Current Portion		Long-Term Debt
(in millions)
Senior Notes
2003 Senior Unsecured Notes		5.35	%		12/19/03		1/15/14	$	500		$	—	$	500
2007 Senior Unsecured Notes		6.20	%		9/28/07		10/1/17		700			—		700
2009 Senior Unsecured Notes		5.20	%		9/23/09		10/1/19		600			—		600
2010 Senior Unsecured Notes		4.00	%		9/30/10		10/1/20		550			—		550
2012 Senior Unsecured Notes		4.25	%		6/18/12		6/15/22		523			—		523
2009 Senior Unsecured Notes		6.25	%		9/23/09		10/1/39		900			—		900
2010 Senior Unsecured Notes		5.75	%		9/30/10		10/1/41		350			—		350
2012 Senior Unsecured Notes		5.60	%		6/18/12		6/15/42		787			—		787
CEG Senior Notes^(a)		4.55	%		6/13/03		6/15/15		550			—		550
CEG Senior Notes^(a)		5.15	%		12/14/10		12/1/20		550			—		550
CEG Senior Notes^(a)		7.60	%		3/26/02		4/1/32		259			—		259
CEG Senior Notes^(a)		8.625	%		6/27/08		6/15/63		450			—		450
Exelon Wind		2.00	%		12/10/10		7/31/17		1			—		1

Total Senior Notes								$	6,720		$	—	$	6,720

Non Regulated Business
Pollution Control Loan^(b)		4.10	%		12/20/84		7/1/14	$	20		$	20	$	—
Solar Revolver		2.49	%		7/7/11		7/7/14		124			—		124
CEU Credit Agreement		1.99	%		7/22/11		7/22/16		37			—		37
MEDCO Tax-exempt Bonds		0.18	%		5/17/06		4/1/24		75			—		75
Sacramento PV Energy
Loan Agreement		3.06	%		7/26/11		12/31/30		40			2		38
Denver Airport Solar
Loan Agreement		5.50	%		6/28/11		6/30/31		7			—		7
Holyoke Solar Loan Agreement		5.25	%		10/25/11		12/31/31		11			—		11
AVSR1-Draw 1		3.09	%		4/5/12		1/5/37		69			—		69

Total Non Regulated Business								$	383		$	22	$	361

Notes Payable
Capital Leases								$	33		$	3	$	30

Unamortized Debt Discount & Premium, Fair Value Amortization, Net									(2	)		—		(2	)
CEG Senior Notes Fair Market Value Adjustment									235			—		235

Total Long-Term Debt								$	7,369		$	25	$	7,344


Maturities		2012			2013		2014		2015			2016
	$	3		$	3	$	647	$	553		$	40

(a)	These notes represent inter company loan agreements between Exelon and Generation that mirror the terms and amounts of the third-party obligations of Exelon.

(b)	Subject to the holder having the option to put the bonds back to Generation; as such they are classified in the current portion of long-term debt.

Long-Term Debt Outstanding as of June 30, 2012

ComEd


Series	Interest Rate			Date Issued		Maturity Date		Total Debt Outstanding			Current Portion		Long-Term Debt
(in millions)
First Mortgage Bonds
92		7.625	%		4/15/93		4/15/13	$	125		$	125	$	—
94		7.50	%		7/1/93		7/1/13		127			—		127
110		1.63	%		1/18/11		1/15/14		600			—		600
Pollution Control-1994C		5.85	%		1/15/94		1/15/14		17			—		17
101		4.70	%		4/7/03		4/15/15		260			—		260
104		5.95	%		8/28/06		8/15/16		415			—		415
106		6.15	%		9/10/07		9/15/17		425			—		425
108		5.80	%		3/27/08		3/15/18		700			—		700
109		4.00	%		8/2/10		8/1/20		500			—		500
111		1.95	%		9/7/11		9/1/16		250			—		250
112		3.40	%		9/7/11		9/1/21		350			—		350
100		5.875	%		1/22/03		2/1/33		254			—		254
103		5.90	%		3/6/06		3/15/36		625			—		625
107		6.45	%		1/16/08		1/15/38		450			—		450

Total First Mortgage Bonds								$	5,098		$	125	$	4,973

Notes Payable
Notes Payable		6.95	%		7/16/98		7/15/18	$	140		$	—	$	140

Total Notes Payable								$	140		$	—	$	140

Long-Term Debt To Financing Trusts
Subordinated Debentures to ComEd Financing III		6.35	%		3/17/03		3/15/33	$	206		$	—	$	206

Total Long-Term Debt to Financing Trusts								$	206		$	—	$	206

Unamortized Debt Disc. & Prem., Net									(22	)		—		(22	)

Total Long-Term Debt								$	5,422		$	125	$	5,297

Note: Amounts may not add due to rounding.

Maturities		2012			2013		2014		2015			2016
		—		$	252	$	617	$	260		$	665

Long-Term Debt Outstanding as of June 30, 2012

PECO


Series	Interest Rate			Date Issued		Maturity Date		Total Debt Outstanding			Current Portion		Long-Term Debt
(in millions)
First Mortgage Bonds (FMB)
FMB		4.75	%		9/23/02		10/1/12	$	225		$	225	$	—
FMB		5.60	%		10/2/08		10/15/13		300			—		300
FMB		5.00	%		3/26/09		10/1/14		250			—		250
FMB		5.35	%		3/3/08		3/1/18		500			—		500
FMB		5.90	%		4/23/04		5/1/34		75			—		75
FMB		5.95	%		9/25/06		10/1/36		300			—		300
FMB		5.70	%		3/19/07		3/15/37		175			—		175

Total First Mortgage Bonds								$	1,825		$	225	$	1,600

Mortgage-Backed Pollution Control Notes
Delaware Co. 2008 Ser. A		4.00	%		3/5/08		12/1/12	$	150		$	150	$	—

Total Mortgage-Backed Pollution Control Notes								$	150		$	150	$	—

Long-Term Debt to Financing Trusts
PECO Energy Capital Trust III		7.38	%		4/6/98		4/6/28	$	81		$	—	$	81
PECO Energy Capital Trust IV		5.75	%		6/24/03		6/15/33		103			—		103

Total Long-Term Debt to Financing Trusts								$	184		$	—	$	184

Unamortized Debt Discount & Premium, Net									(2	)		—		(2	)

Total Long-Term Debt								$	2,157		$	375	$	1,782


Maturities		2012			2013		2014		2015			2016
	$	375		$	300	$	250		—			—

Long-Term Debt Outstanding as of June 30, 2012

BGE


Series	Interest Rate			Date Issued		Maturity Date		Debt Outstanding			Current Portion		Long-Term Debt
(in millions)
Senior Notes
Senior Notes due 7/1/13		6.125	%		6/26/08		7/1/13	$	400		$	—	$	400
Senior Notes due 10/1/16		5.90	%		10/13/06		10/1/16		300			—		300
Senior Notes due 11/15/21		3.50	%		11/16/11		11/15/21		300			—		300
Senior Notes due 6/15/33		5.20	%		6/20/03		6/15/33		200			—		200
Senior Notes due 10/1/36		6.35	%		10/13/06		10/1/36		400			—		400

Total Senior Notes								$	1,600		$	—	$	1,600

Rate Stabilization Bonds
BGE Securitization due 2017		5.683	%		6/28/07		4/1/17	$	363		$	65	$	299

Total Rate Stabilization Bonds								$	363		$	65	$	299

Deferrable Interest Subordinated Debentures
Trust Preferred Debentures due 2043		6.20	%		11/21/03		10/15/43	$	258		$	—	$	258
Total Deferrable Interest Suburdinated Debentures								$	258		$	—	$	258

Unamortized Debt Discount & Premium, Net									(2	)		—		(2	)

Total Long-Term Debt								$	2,219		$	65	$	2,154


Maturities		2012			2013		2014		2015			2016
		—		$	400		—		—		$	300

Federal Regulation

Federal Energy Regulatory Commission (FERC)

(www.ferc.gov)

The FERC has five full-time members, each appointed by the President of the United States and confirmed by the U.S. Senate. The Commissioners serve for staggered five-year terms. No more than three Commissioners may belong to the same political party. The Chairman is designated by the President.


Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Jon Wellinghoff (Chairman)	Democrat	7/06	6/13	Attorney, practice focused on energy law and utility regulation; staff advisor to several state utility commissions; Nevada State Consumer Advocate

Philip D. Moeller	Republican	7/06	6/15	Energy policy advisor to former U.S. Senator Slade Gorton (WA); staff coordinator for the WA State Senate Committee on Energy, Utilities and Telecommunications; Alliant Energy Corporation

Tony Clark	Republican	6/12	6/16	Chairman of North Dakota Public Service Commission; President of NARUC; North Dakota Labor Commissioner under Gov. Ed Schafer; State Legislator; Chairman of Frontier Trails District of the Boy Scouts of America

John R. Norris	Democrat	1/10	6/17	Attorney; Chief of Staff to Secretary Tom Vilsack of the U.S. Department of Agriculture; Chairman of the Iowa Utilities Board; President of the Organization of MISO States

Cheryl A. LaFleur	Democrat	7/10	6/14	Attorney; executive vice president and acting CEO of National Grid USA; member of the NARUC Committees on Electricity and Critical Infrastructure

ComEd Electric Transmission Rate Cases


($ in millions)	Date		Revenue Adjustment		Test Year	Rate Base		Overall Rate of Return		Return on Equity		Equity Ratio
ComEd Update^(a)		5/16/12		$23	2011 pro forma		$2,104		8.91%		11.50%		55%
ComEd Update^(a)(b)		5/16/11		$6	2010 pro forma		$2,054		9.10%		11.50%		55%
ComEd Update^(a)(c)		5/14/10		$(24)	2009 pro forma		$1,949		9.27%		11.50%		56%
ComEd Update^(a)		5/15/09		$(16)	2008 pro forma		$1,986		9.43%		11.50%		57%

(a)	Annual update filing based on the formula rate, originally implemented effective May 1, 2007. Rate effective June 1 of the update year through May 31 of the following year.

(b)	Revenue requirement increase primarily reflects the IL income tax statuatory rate change enacted January 2011.

(c)	Revenue requirement decrease primarily reflects lower O&M expenses and increased true-up credit to the formula.

BGE Electric Transmission Rate Cases


($ in millions)	Date		Revenue Adjustment			Test Year	Rate Base		Overall Rate of Return			Return on Equity			Equity Ratio
BGE Update^(a),(b)		4/24/12	$	18		2011 pro forma	$	572		8.43	%		11.30	%		50	%
BGE Update^(a)		4/29/11	$	(1	)	2010 pro forma	$	501		8.96	%		11.30	%		53	%
BGE Update^(a),(b)		4/26/10	$	33		2009 pro forma	$	441		8.92	%		11.30	%		51	%
BGE Update^(a)		5/4/09	$	3		2008 pro forma	$	392		8.47	%		11.30	%		45	%

(a)	Annual update filing based on the formula rate, originally implemented effective June 1, 2005. Rate effective June 1 of the update year through May 31 of the following year.

(b)	Revenue requirement increase primarily reflects higher rate base, O&M expenses, and true-up debit to the formula.

State Regulation

Illinois Commerce Commission (ICC)

(www.icc.illinois.gov)

The ICC has five full-time members, each appointed by the Governor (currently Pat Quinn, Democrat; term began in January 2009 and ends in January 2015) and confirmed by the Illinois State Senate. The Commissioners serve staggered five-year terms. Under Illinois law, no more than three Commissioners may belong to the same political party. The Chairman is designated by the Governor.


Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Douglas P. Scott (Chairman)	Democrat	3/11	1/14	Attorney; director of the Illinois Environmental Protection Agency; mayor of Rockford, IL; IL state representative

Ann McCabe	Republican	3/12	1/17	Midwest regional director for The Climate Registry; partner at Policy Solutions Ltd.; regulatory manager for BP and Amoco; founding member of the Foresight Sustainable Business Alliance; member Illinois Environmental Council

Lula M. Ford	Democrat	1/03	1/13	Assistant superintendent, Chicago Public Schools; teacher; assistant director, Central Management Service

Erin O’Connell-Diaz	Republican	4/03	1/13	Attorney; ICC Administrative Law Judge; assistant attorney general

John T. Colgan	Democrat	11/09	1/15	Member of Illinois Association of Community Action Agencies; executive director of the Illinois Hunger Coalition

ComEd Electric Distribution Rate Cases


($ in millions)	Date		Revenue Increase			Test Year		Rate Base			Overall Rate of Return			Return on Equity			Equity Ratio
Formula Rate Filing		11/8/11	($	59	)		2010	$	6,601			8.11	%		10.05	%		45.56	%
ICC Order^(a)		5/29/12	($	169	)		2010	$	6,183			8.16	%		10.05	%		46.17	%

ComEd Request		6/30/10	$	343	^(b)		2009	$	7,349	^(a)		8.98	%^(a)		11.50	%		47.28	%^(a)
ICC Order		5/24/11	$	143			2009	$	6,549			8.51	%		10.50	%		47.28	%

ComEd Request		10/17/07	$	345	^(c)		2006	$	6,753	^(b)		8.57	%^(b)		10.75	%		45.04	%^(b)
ICC Order^(d)		9/10/08	$	274			2006	$	6,694			8.36	%		10.30	%		45.04	%

ComEd Request		8/31/05	$	317			2004	$	6,187			8.94	%		11.00	%		54.20	%
ICC Order		12/20/06	$	83			2004	$	5,521			8.01	%		10.045	%		42.86	%

(a)	On June 22, 2012 the ICC granted expedited rehearing on three aspects of the formula rate order. The expected schedule for the rehearing allows for a decision by September 19, 2012.

(b)	Reflects ComEd reply brief filed on February 23, 2011. Original rate request included a $396 million revenue increase.

(c)	Reflects ComEd surrebuttal testimony filed on April 21, 2008. Original rate request included a $361 million revenue increase.

(d)

On September 30, 2010, the Illinois Appellate Court issued a decision in the appeals related to the ICC’s order in ComEd’s 2007 electric distribution rate case. That decision ruled against ComEd on the treatment of post-test year accumulated depreciation. On November 18, 2010, the Court denied ComEd’s petition for rehearing, and on January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court.

ComEd – Average Total Residential Rate


($/MWh) Year	Transmission		Distribution		Energy		Other^(a)		Total
2008		6.90		33.77		72.55		2.46		115.68
2009		6.94		39.29		67.77		3.02		117.02
2010		6.80		38.71		72.81		3.34		121.66
2011		7.49		41.40		73.14		3.78		125.80

(a)	Primarily includes taxes and environmental cost recovery and energy efficiency riders.

State Regulation

Pennsylvania Public Utility Commission (PUC)

(www.puc.state.pa.us)

The PUC has five full-time members, each appointed by the Governor (currently Tom Corbett, Republican; term began in January 2011 and ends in January 2015) and confirmed by the Pennsylvania State Senate. The Commissioners serve for staggered five-year terms. Under Pennsylvania law, no more than three Commissioners may belong to the same political party as the Governor. The Chairman is designated by the Governor, and the Vice Chairman is selected by the PUC commissioners.


Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Robert F. Powelson (Chairman)	Republican	6/08	4/14	President/CEO of Chester County Chamber of Business and Industry; staff assistant to former U.S. Representative Curt Weldon (PA)

John F. Coleman Jr. (Vice Chairman)	Republican	6/10	4/17	President/CEO of Centre County Chamber of Business and Industry; Executive Director of the Jefferson County Department of Development

Pamela A. Witmer	Republican	6/11	4/16	Energy and environment practice lead at Bravo Group. President and CEO of Pennsylvania Chemical Industry Council; lead legislative liaison in PA Department of Environmental Protection; research analyst for PA House of Representatives

Wayne E. Gardner	Democrat	6/08	4/13	Consultant in power generation technologies; executive at Franklin Fuel Cells, Inc.; executive at PECO Energy

James H. Cawley	Democrat	6/05	4/15	Attorney; majority counsel to the Pennsylvania Senate Consumer Affairs Committee

PECO Electric Distribution Rate Case


($ in millions)	Date		Revenue Increase		Test Year		Rate Base		Overall Rate of Return			Return on Equity			Equity Ratio
PECO Request^(a)		3/31/10	$	316		2010	$	3,236		8.95	%		11.75	%		53.18	%
PUC Order^(b)		12/16/10	$	225		2010		n/a		n/a			n/a			n/a

PECO Gas Delivery Rate Cases


($ in millions)	Date		Revenue Increase		Test Year		Rate Base		Overall Rate of Return			Return on Equity			Equity Ratio
PECO Request^(a)		3/31/10	$	44		2010	$	1,100		8.95	%		11.75	%		53.18	%
PUC Order^(b)		12/16/10	$	20		2010		n/a		n/a			n/a			n/a

PECO Request		3/31/08	$	98		2008	$	1,104		8.87	%		11.50	%		54.34	%
PUC Order^(b)		10/23/08	$	77		2008		n/a		n/a			n/a			n/a

(a)	Per original filing.

(b)	PUC approved a joint settlement; no allowed return was specified. Increase related to December 2010 order was effective January 1, 2011.

PECO — Average Total Residential Rate


($/MWh) Year	Transmission		Distribution		Energy Efficiency Surcharge		CTC^(c)		Energy and Capacity		Total
2010	$	5.10	$	50.30	$	2.90	$	25.70	$	62.60	$	146.60
2011		6.90		58.40		4.70		—		84.00		154.00

(c)	The PUC authorized recovery in PECO’s 1998 settlement of competitive transition charges (CTC) through 2010.

State Regulation

Maryland Public Service Commission (PSC)

(http://webapp.psc.state.md.us)

The PSC has five full-time members, each appointed by the Governor (currently Martin O’Malley, Democrat; 1st term began in January 2007; 2nd term ends in January 2015) and confirmed by the Maryland General Assembly. The Commissioners serve staggered five-year terms.


Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Douglas R. M. Nazarian (Chairman)	Democrat	8/08	6/13	Attorney; NARUC Board of Directors; President of Organization of PJM States; President of Eastern Interconnection States’ Planning Council; General Counsel of MDPSC, attorney in private practice; clerk at U.S. Court of Appeals for the Eighth Circuit

Harold D. Williams	Democrat	9/02	6/17	Director of Corporate Procurement Services at BGE; Chair of NARUC’s Utility Market Access partnership Board; Chairman of MD/DC Minority Supplier Development Council; Board member of EEI Minority Business Development Committee, and DOE Minority Business Roundtable Committee

Lawrence Brenner	Democrat	3/07	6/15	Attorney; Chairman of Washington Metropolitan Area Transit Commission; Board member of Organization of PJM States; Deputy Chief ALJ for FERC; judge for the NRC; ALJ with U.S. Department of Labor

Kelly Speakes-Backman	Democrat	9/11	6/14	Board member of NARUC Committee on Energy Resources and the Environment and Regionall Greenhouse Gas Initiative; Clean Energy director at Maryland Energy Administration

W. Kevin Hughes	Democrat	9/11	6/16	Attorney; Deputy Legislative Officer to Governors O’Malley, Glendening; Legislative Officer under Governor Schaefer; Principal Analyst for MD Department of Legislative Services


BGE Electric Distribution Rate Case

($ in millions)	Date			Revenue Increase			Test Year		Adjusted Rate Base		Overall Rate of Return			Return on Equity			Equity Ratio
BGE Request		7/27/12		$	151			2011-12	$	2,714		8.02	%		10.5	%		48.4	%
BGE Request		5/7/10		$	92	^(a)		2009-10	$	2,291		8.99	%		11.65	%		51.93	%
PSC Order		12/6/10	^(b)	$	31			2009-10	$	2,243		8.06	%		9.86	%		51.93	%


BGE Gas Distribution Rate Case

($ in millions)	Date			Revenue Increase		Test Year		Adjusted Rate Base		Overall Rate of Return			Return on Equity			Equity Ratio
BGE Request		7/27/12		$	53		2011-12	$	1,018		8.02	%		10.5	%		48.4	%
BGE Request		5/7/10		$	30		2009-10	$	839		8.99	%		11.65	%		51.93	%
PSCOrder		12/6/10	^(b)	$	10		2009-10	$	817		7.90	%		9.56	%		51.93	%

(a)	However, due to a 2008 settlement with the MDPSC, the State of Maryland and the General Assembly, BGE’s electric rate increase was limited to 5% of electricity revenues or $47.2 million.

(b)	The PSC issued an abbreviated rate order on December 6, 2010 and followed-up with a more comprehensive order on March 9 2011.


BGE – Average Total Residential Rate
($/MWh)
Year	Energy		Transmission		Distribution		Other^(a)		Total
2010	$	109.30	$	5.12	$	31.35	$	3.07	$	148.84
2011		93.39		6.13		33.05		4.33		136.90

(a)	Includes EmPowerMD Charge, RSP Charge/Misc Credits, taxes, and other surcharges.

Capital Structure and Capitalization Ratios for Exelon and Operating Companies


(at December 31)	2011				2010				2009
	(in millions)		(in percent)		(in millions)		(in percent)		(in millions)		(in percent)		(in percent)^(a)
Exelon (consolidated)
Total Debt	$	13,405		48.1	$	12,828		48.4	$	12,594		49.7		48.9
Preferred Securities of Subsidiaries		87		0.3		87		0.3		87		0.3		0.3
Total Equity		14,388		51.6		13,563		51.2		12,640		49.9		50.8

Total Capitalization	$	27,880			$	26,478			$	25,321

Transition Debt	$	—			$	—			$	415

Exelon Generation
Total Debt^(b)	$	3,679		29.7	$	3,679		33.9	$	2,993		30.6
Total Equity		8,708		70.3		7,177		66.1		6,792		69.4

Total Capitalization	$	12,387			$	10,856			$	9,785


ComEd
Total Debt	$	5,871		45.5	$	5,207		43.0	$	5,072		42.7
Total Shareholders’ Equity		7,037		54.5		6,910		57.0		6,882		57.6

Total Capitalization	$	12,908			$	12,117			$	11,954


PECO
Total Debt^(b)	$	2,381		44.0	$	2,631		47.0	$	2,820		51.5		47.6
Preferred Securities		87		1.6		87		1.6		87		1.6		1.7
Total Shareholders’ Equity		2,938		54.3		2,883		51.5		2,565		46.9		50.7

Total Capitalization	$	5,406			$	5,601			$	5,472

Transition Debt	$	—			$	—			$	415

Note: Percentages may not add due to rounding.

(a)	Excluding PECO transition debt.

(b)	Includes PECO’s accounts receivable agreement at December 31, 2010 and 2011 of $225 million, which is classified as a short-term note payable.

Financial and Operating Highlights for Exelon in 2011


	For the Years ended December 31,
(in millions, except per share data and where indicated)	2011		2010		2009
Operating revenues	$	18,924	$	18,644	$	17,318
Net income	$	2,495	$	2,563	$	2,707
Electric deliveries (in GWh)^(a)		128,151		130,778		124,828
Gas deliveries (in million cubic feet (mmcf))		82,443		87,744		84,309
Total available electric supply resources (MW)		30,569		31,758		31,003
Cash flows from operating activities	$	4,853	$	5,244	$	6,094
Capital expenditures	$	4,042	$	3,326	$	3,273

Common Stock Data
Average common shares outstanding – diluted (in millions)		665		663		662
GAAP earnings per share (diluted)	$	3.75	$	3.87	$	4.09
Adjusted (non-GAAP) operating earnings per share (diluted)	$	4.16	$	4.06	$	4.12
Dividends paid per common share	$	2.10	$	2.10	$	2.10

New York Stock Exchange common stock price (per share)
High	$	45.45	$	49.88	$	58.98
Low	$	39.06	$	37.24	$	38.41
Year end	$	43.37	$	41.64	$	48.87

Book value per share	$	21.69	$	20.49	$	19.16
Total market capitalization (year end)	$	28,770	$	27,557	$	32,244
Common shares outstanding (year end)		663.4		661.8		659.8

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

Reconciliation of Adjusted (non-GAAP) Operating Earnings Per Share to GAAP


	2011			2010			2009
GAAP Earnings per Diluted Share	$	3.75		$	3.87		$	4.09
Mark-to-market impact of economic hedging activities		0.27			(0.08	)		(0.16	)
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments		—			(0.08	)		(0.19	)
Retirement of fossil generating units		0.05			0.08			0.05
Asset retirement obligation updates		0.02			(0.01	)		(0.05	)
Constellation acquisition costs		0.07			—			—
Acquisition costs for Exelon Wind (2010) and Antelope Valley Solar Ranch One (2011)		0.01			0.01			—
Non-cash charge resulting from IL tax rate change		0.04			—			—
Wolf Hollow Acquisition		(0.03	)		—			—
Recovery of costs pursuant to distribution rate case order		(0.03	)		—			—
Non-cash remeasurement of deferred income taxes		0.01			—			—
Impact of the 2007 Illinois electric rate settlement		—			0.02			0.10
Impairment of certain emissions allowances		—			0.05			—
Costs associated with ComEd’s City of Chicago settlement		—			—			0.01
Non-cash charge resulting from health care legislation		—			0.10			—
Non-cash remeasurement of income tax uncertainties and reassessment of state deferred income taxes		—			0.10			0.10
Impairment of certain generating assets		—			—			0.20
Costs associated with early debt retirements		—			—			0.11
External costs associated with the proposed acquisition of NRG Energy, Inc. (NRG)		—			—			0.03
2009 restructuring charges		—			—			0.03

Adjusted (non-GAAP) Operating Earnings per Diluted Share	$	4.16		$	4.06		$	4.12

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

Exelon Corporation


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
(in millions, except per share data)	GAAP^(a)			Adjustments			Adjusted Non-GAAP			GAAP^(a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	18,924		$	(66	)^(c),(d)	$	18,858		$	18,644		$	25	^(m),(n)	$	18,669
Operating expenses
Purchased power		5,284			(214	)^(e)		5,070			4,425			(3	)^(e)		4,422
Fuel		1,844			(78	)^(c),(e)		1,766			2,010			32	^(e),(o)		2,042
Operating and maintenance		5,012			(124	)^{(c),(d),(f),(g),(h),(i)}		4,888			4,453			(4	)^{(c),(f),(h),(p)}		4,449
Operating and maintenance for regulatory required programs^(b)		184			—			184			147			—			147
Depreciation and amortization		1,335			(87	)^(c)		1,248			2,075			(80	)^(c)		1,995
Taxes other than income		785			(1	)^(c)		784			808			—			808

Total operating expenses		14,444			(504	)		13,940			13,918			(55	)		13,863

Operating income		4,480			438			4,918			4,726			80			4,806

Other income and deductions
Interest expense, net		(726	)		—			(726	)		(817	)		103	^(q)		(714	)
Loss in equity method investments		(1	)		—			(1	)		—			—			—
Other, net		199			(21	)^(d),(j)		178			312			(153	)^(j),(q)		159

Total other income and deductions		(528	)		(21	)		(549	)		(505	)		(50	)		(555	)

Income before income taxes		3,952			417			4,369			4,221			30			4,251
						^{(c),(d),(e),(f),(g)}									^{(c),(e),(f),(h),(j)}
Income taxes		1,457			149	^{(h),(i),(j),(k),(l)}		1,606			1,658			(96	)^{(m),(n),(o),(p),(q)}		1,562

Net income	$	2,495		$	268		$	2,763		$	2,563		$	126		$	2,689

Effective tax rate		36.9	%					36.8	%		39.3	%					36.7	%

Earnings per average common share
Basic	$	3.76		$	0.41		$	4.17		$	3.88		$	0.19		$	4.07
Diluted	$	3.75		$	0.41		$	4.16		$	3.87		$	0.19		$	4.06
Average common shares outstanding
Basic		663			—			663			661			—			661
Diluted		665			—			665			663			—			663

(a)	Results reported in accordance with GAAP.

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(d)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(e)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(f)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion and the decrease in PECO’s asset retirement obligation in 2011, and a decrease in ComEd and PECO’s asset retirement obligations in 2010.

(g)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(h)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

(i)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(j)	Adjustment to exclude the unrealized losses in 2011 and unrealized gains in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(k)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(l)	Adjustment to exclude the non-cash charge impacts of the annual remeasurement of state deferred income taxes.

(m)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(n)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(o)	Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(p)	Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(q)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

Exelon Generation


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
(in millions)	GAAP^(a)			Adjustments			Adjusted Non-GAAP			GAAP^(a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	10,308		$	(66	)^(b),(c)	$	10,242		$	10,025		$	21	^(k)	$	10,046
Operating expenses
Purchased power		1,922			(214	)^(d)		1,708			1,853			(3	)^(d)		1,850
Fuel		1,528			(78	)^(b),(d)		1,450			1,610			32	^(d),(l)		1,642
Operating and maintenance		3,148			(77	)^{(b),(c),(e),(f),(g)}		3,071			2,812			(18	)^(b),(f),(m)		2,794
Depreciation and amortization		570			(87	)^(b)		483			474			(80	)^(b)		394
Taxes other than income		264			(1	)^(b)		263			230			—			230

Total operating expenses		7,432			(457	)		6,975			6,979			(69	)		6,910

Operating income		2,876			391			3,267			3,046			90			3,136

Other income and deductions
Interest expense, net		(170	)		—			(170	)		(153	)		—			(153	)
Loss in equity method investments		(1	)		—			(1	)		—			—			—
Other, net		122			(21	)^(c),^(h)		101			257			(155	)^(h)		102

Total other income and deductions		(49	)		(21	)		(70	)		104			(155	)		(51	)

Income before income taxes		2,827			370			3,197			3,150			(65	)		3,085
Income taxes		1,056			139	^{(b),(c),(d),(e),}^{(f),(g),(h),(i),(j)}		1,195			1,178			(21	)^{(b),(d),(f),(h),}^{(k),(l),(m),(n)}		1,157

Net income	$	1,771		$	231		$	2,002		$	1,972		$	(44	)	$	1,928

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude costs associated with the planned retirement of fossil generating units and the impacts of the FERC approved reliability-must-run rate schedule.

(c)	Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(d)	Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities.

(e)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(f)	Adjustment to exclude certain costs associated with Exelon’s acquisition of Exelon Wind in 2010 and Exelon’s acquisition of AVSR 1 in 2011.

(g)	Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at Zion.

(h)	Adjustment to exclude the unrealized losses in 2011 and unrealized gains in 2010 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(i)	Adjustment to exclude the non-cash impacts of the annual remeasurement of state deferred income taxes.

(j)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(k)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(l)	Adjustment to exclude a non-cash charge for the impairment of certain SO2 emission allowances as a result of declining market prices following the release of the EPA’s proposed Transport Rule in the third quarter of 2010.

(m)	Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(n)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

ComEd


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
(in millions)	GAAP^(a)			Adjustments			Adjusted Non-GAAP			GAAP^(a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,056		$	—		$	6,056		$	6,204		$	4	^(e),(f)	$	6,208

Operating expenses
Purchased power		3,035			—			3,035			3,307			—			3,307
Operating and maintenance		1,086			13	^(c)		1,099			975			7	^(g),(h)		982
Operating and maintenance for regulatory required programs^(b)		115			—			115			94			—			94
Depreciation and amortization		542			—			542			516			—			516
Taxes other than income		296			—			296			256			—			256

Total operating expenses		5,074			13			5,087			5,148			7			5,155

Operating income		982			(13	)		969			1,056			(3	)		1,053

Other income and deductions
Interest expense, net		(345	)		—			(345	)		(386	)		59	⁽ⁱ⁾		(327	)
Other, net		29			—			29			24			—			24
Total other income and deductions		(316	)		—			(316	)		(362	)		59			(303	)

Income before income taxes		666			(13	)		653			694			56			750
Income taxes		250			—	^(c),(d)		250			357			(59	)^{(e),(f),(g),(h),(i)}		298

Net income	$	416		$	(13	)	$	403		$	337		$	115		$	452

(a)	Results reported in accordance with GAAP.

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c)	Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(d)	Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(e)	Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(f)	Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(g)	Adjustment to exclude a decrease in 2010 in ComEd’s asset retirement obligation.

(h)	Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(i)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

PECO


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010
(in millions)	GAAP^(a)			Adjustments			Adjusted Non-GAAP			GAAP^(a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	3,720		$	—		$	3,720		$	5,519		$	—		$	5,519
Operating expenses
Purchased power		1,547			—			1,547			2,361			—			2,361
Fuel		317			—			317			401			—			401
Operating and maintenance		725			1	^(c),(d)		726			680			(1	)^(d),(e)		679
Operating and maintenance for regulatory required programs^(b)		69			—			69			53			—			53
Depreciation and amortization		202			—			202			1,060			—			1,060
Taxes other than income		205			—			205			303			—			303

Total operating expenses		3,065			1			3,066			4,858			(1	)		4,857

Operating income		655			(1	)		654			661			1			662
Other income and deductions
Interest expense, net		(134	)		—			(134	)		(193	)		36	^(f)		(157	)
Loss in equity method investments		—			—			—			—			—			—
Other, net		14			—			14			8			2	^(f)		10

Total other income and deductions		(120	)		—			(120	)		(185	)		38			(147	)

Income before income taxes		535			(1	)		534			476			39			515
Income taxes		146			—	^(c),(d)		146			152			8	^(d),(e),(f)		160

Net income	$	389		$	(1	)	$	388		$	324		$	31		$	355

(a)	Results reported in accordance with GAAP.

(b)	Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c)	Adjustment to exclude certain costs associated with Exelon’s proposed acquisition of Constellation.

(d)	Adjustment to exclude a decrease in 2011 and 2010 in PECO’s asset retirement obligation.

(e)	Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(f)	Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

Supply and Sales Statistics

Exelon Generation – Annual Electric Supply and Sales Statistics


	Twelve Months Ended December 31,
(in GWhs)	2011		2010
Supply
Nuclear Generation^(a)
Mid-Atlantic		47,287		47,517
Midwest		92,010		92,493

Total Nuclear Generation		139,297		140,010

Fossil and Renewables
Mid-Atlantic^(a),(b)		7,580		9,436
Midwest		596		68
South and West		3,462		1,213

Total Fossil and Renewables		11,638		10,717

Purchased Power
Mid-Atlantic		2,898		1,918
Midwest		5,970		7,032
South and West		10,040		12,112

Total Purchased Power		18,908		21,062

Total Supply by Region
Mid-Atlantic		57,765		58,871
Midwest		98,576		99,593
South and West		13,502		13,325

Total Supply		169,843		171,789

Electric Sales
ComEd^(c)		—		5,323
PECO^(d)		—		42,003
Market and Retail^(c),(d)		169,843		124,463

Total Electric Sales^(e)		169,843		171,789

Average Margin ($/MWh)^(f),(g),^(h)
Mid-Atlantic	$	58.15	$	42.67
Midwest		35.98		40.98
South and West		5.18		(9.83	)
Average Margin – Overall Portfolio		41.07		37.62
Around-the-clock (ATC) Market Prices ($/MWh)⁽ⁱ⁾
PJM West Hub	$	43.56	$	45.93
NIHUB		33.07		33.09
ERCOT North Spark Spread		11.88		2.31

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)	ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the Request for Proposal (RFP) are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales.

(d)	PECO line item represents sales under the 2006 PECO PPA. Sales to PECO through the competitive procurement process are included within market and retail sales.

(e)	Total sales do not include trading volume of 5,742 GWhs and 3,625 GWhs for the years ended December 31, 2011 and 2010, respectively.

(f)	Excludes retail gas activity, trading portfolio and other operating revenue.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the year.

Exelon Generation – Financial Swap Agreement with ComEd


Portion of Term	Fixed Price ($/MWh)		Notional Quantity (MW)^(a)
January 1, 2012 – December 31, 2012	$	52.37		3,000
January 1, 2013 – May 31, 2013	$	53.48		3,000

(a)	Market-based contract for ATC baseload energy only; does not include capacity, ancillary services or congestion. Agreement effective June 1, 2008.

Supply and Sales Statistics

Exelon Generation – Electric Supply and Sales by Quarter


	Three Months Ended
(in GWhs)	December 31, 2011			September 30, 2011		June 30, 2011			March 31, 2011			December 31, 2010
Supply
Nuclear Generation^(a)
Mid-Atlantic		11,587			12,158		11,172			12,370			11,974
Midwest		23,306			23,887		21,995			22,822			23,141

Total Nuclear Generation		34,893			36,045		33,167			35,192			35,115
Fossil and Renewables
Mid-Atlantic^(a)(b)		1,637			1,724		2,054			2,166			2,115
Midwest^(c)		188			88		163			157			45
South and West^(c)		851			1,463		638			509			93

Total Fossil and Renewables		2,676			3,275		2,855			2,832			2,253
Purchased Power
Mid-Atlantic		739			702		707			750			442
Midwest		1,143			1,756		1,659			1,412			1,776
South and West		1,632			3,815		2,411			2,181			2,632

Total Purchased Power		3,514			6,273		4,777			4,343			4,850
Total Supply by Region
Mid-Atlantic		13,963			14,584		13,933			15,286			14,531
Midwest		24,637			25,731		23,817			24,391			24,962
South and West		2,483			5,278		3,049			2,690			2,725

Total Supply		41,083			45,593		40,799			42,367			42,218


	Three Months Ended
(in GWhs)	December 31, 2011			September 30, 2011		June 30, 2011			March 31, 2011			December 31, 2010
Electric Sales
PECO^(d)		—			—		—			—			9,756
Market and Retail^(d)		41,083			45,593		40,799			42,367			32,462

Total Electric Sales^(e)		41,083			45,593		40,799			42,367			42,218

Average Margin ($/MWh)^(f),(g),(h)
Mid-Atlantic	$	56.29		$	57.32	$	58.92		$	59.92		$	51.75
Midwest		34.18			33.15		37.28			39.60			41.14
South and West		(5.24	)		18.57		(3.61	)		(1.49	)		(10.64	)
Average Margin – Overall Portfolio		39.31			39.19		41.59			44.30			41.45

Around-the-clock Market Prices ($/MWh)⁽ⁱ⁾
PJM West Hub	$	35.07		$	46.17	$	47.27		$	45.82		$	43.65
NiHUB		25.97			37.30		34.94			34.10			27.26
ERCOT North Spark Spread		1.11			36.70		6.73			8.00			(0.69	)

(a)	Includes Generation’s proportionate share of the output of its jointly owned generating plants.

(b)	Includes New England generation.

(c)

Includes generation from Exelon Wind, acquired in December, 2010, of 186 GWh, 76 GWh, 154 GWh, 155 GWh and 41 GWh in the Midwest and 394 GWh, 249 GWh, 431 GWh, 358 GWh and 84 GWh in the South and West for the three months ended December 31, 2011, September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010, respectively.

(d)	PECO line item represents sales under the PECO PPA. Settlements of the ComEd swap, sales under the Request for Proposal (RFP) and sales to PECO through the competitive procurement process are included within Market and Retail sales.

(e)	Total sales do not include physical trading volume of 1,235 GWh, 1,679 GWh, 1,496 GWh, 1,333 GWh, and 740 GWh for the three months ended December 31, 2011,September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010 respectively.

(f)	Excludes retail gas activity, trading portfolio activity and amounts paid related to the Illinois Settlement Legislation and compensation under the reliability-must-run rate schedule.

(g)	Excludes the mark-to-market impact of Generation’s economic hedging activities.

(h)	Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(i)	Represents the average for the quarter.

Supply and Sales Statistics

ComEd – Electric Sales Statistics, Revenue and Customer Detail


	2011			2010
Retail Deliveries^(a)(in GWhs)
Residential		28,273			29,171
Small Commercial & Industrial		32,281			32,904
Large Commercial & Industrial		27,732			27,717
Public Authorities & Electric Railroads		1,235			1,273

Total Retail Deliveries		89,521			91,065

Electric Revenue (in millions)
Retail Revenues^(a)
Residential	$	3,510		$	3,549
Small Commercial & Industrial		1,517			1,639
Large Commercial & Industrial		383			397
Public Authorities & Electric Railroads		50			62

Total Retail Revenues		5,460			5,647

Other Revenues^(b)		596			557

Total Electric Revenues	$	6,056		$	6,204


Customers at Year End
	2011			2010
Retail Deliveries Customers
Residential		3,448,481			3,438,677
Small Commercial & Industrial		365,824			363,393
Large Commercial & Industrial		2,032			2,005
Public Authorities & Electric Railroads		4,797			5,078

Total Retail Deliveries Customers		3,821,134			3,809,153


Heating and Cooling Degree Days

	2011			2010
Heating Degree Days (normal=6,362)		6,134			5,991
Cooling Degree Days (normal=855)		1,036			1,181

Peak System Load
	2011			2010
Summer^(d)
Highest Peak Load (MW)		23,753	^(c)		21,914
Winter^(f)
Highest Peak Load (MW)		15,656			16,092

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy.

(b)	Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM).

(c)	Refers to the normal time period of 30 years ending 2006. As of calendar year 2012 ComEd began using a new normal time period: 30 years ending 2010. The HDD and CDD normals for this period are 6,340 and 842, respectively.

(d)	Summer is defined as June 1 to September 30 of the reporting year.

(e)	The summer peak load of 23,753 MW that occured on July 20, 2011 is the all-time peak load for ComEd.

(f)	Winter is defined as November 1 of the previous year to March 31 of the reporting year.

Supply and Sales Statistics

PECO – Electric Sales Statistics, Revenue and Customer Detail


	2011			2010
Retail Deliveries^(a)(in GWhs)
Residential		13,687			13,913
Small Commercial & Industrial		8,321			8,503
Large Commercial & Industrial		15,677			16,372
Public Authorities & Electric Railroads		945			925

Total Retail Deliveries		38,630			39,713


Electric Revenue (in millions)
Retail Revenues^(a)
Residential	$	1,934		$	2,069
Small Commercial & Industrial		584			1,060
Large Commercial & Industrial		304			1,362
Public Authorities & Electric Railroads		38			89

Total Retail Revenues		2,860			4,580

Other Revenues^(b)		249			255

Total Electric Revenues	$	3,109		$	4,835


Customers at Year End
	2011			2010
Retail Deliveries Customers
Residential		1,415,681			1,411,643
Small Commercial & Industrial		157,137			156,865
Large Commercial & Industrial		3,110			3,071
Public Authorities & Electric Railroads		1,122			1,102

Total Retail Deliveries Customers		1,577,050			1,572,681


Heating and Cooling Degree Days
	2011			2010
Heating Degree Days (normal=4,638)		4,157			4,396
Cooling Degree Days (normal=1,292)		1,617			1,817

Peak System Load
	2011			2010
Summer^(c)
Highest Peak Load (MW)		8,983	^(d)		8,864
Winter^(d)
Highest Peak Load (MW)		6,675			6,333

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges and a CTC. For customers purchasing electricity from PECO, revenue also reflects the cost of energy.

(b)	Other revenue includes transmission revenue from PJM and wholesale revenues.

(c)	Summer is defined as June 1 to September 30 of the reporting year.

(d)	The summer peak load of 8,983 MW that occured on July 22, 2011 is the all-time peak load for PECO.

(e)	Winter is defined as November 1 of the previous year to March 31 of the reporting year.

Supply and Sales Statistics

PECO – Gas Sales Statistics, Revenue and Customer Detail


	2011		2010
Deliveries to Customers (in mmcf)
Retail Sales		54,239		56,833
Transportation		28,204		30,911

Total Gas Deliveries		82,443		87,744

Gas Revenue (in millions)
Retail Sales	$	575	$	656
Transportation and Other		36		28

Total Gas Revenue	$	611	$	684


Gas Customers at Year End
	2011		2010
Customers
Residential		451,382		448,391
Commercial & Industrial		41,373		41,303

Total Retail Customers		492,755		489,694
Transportation		879		838

Total Gas Customers		493,634		490,532


Gas Maximum Day Sendout
	2011		2010
Winter
Maximum Day Sendout (in thousand cubic feet (mcf))		667,061		662,945

Exelon Generation – Total Owned Generating Capacity

Owned net electric generating capacity by station at December 31, 2011:

Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units consist of low-efficiency, quick response steam units, gas turbines, diesels, and pumped-storage hydroelectric equipment normally used during the maximum load periods.

Station

Location

Number
of Units

Percent
Owned^(a)

Primary
Fuel Type

Primary
Dispatch

Type

Net
Generation
Capacity^(b)
(MW)

Nuclear

Braidwood

Braidwood, IL

Uranium

Base-load

2,348

Byron

Byron, IL

Uranium

Base-load

2,323

Clinton

Clinton, IL

Uranium

Base-load

1,067

Dresden

Morris, IL

Uranium

Base-load

1,753

LaSalle

Seneca, IL

Uranium

Base-load

2,316

Limerick

Limerick Twp., PA

Uranium

Base-load

2,312

Oyster Creek

Forked River, NJ

Uranium

Base-load

625

^(c)

Peach Bottom

Peach Bottom Twp., PA

50.00

Uranium

Base-load

1,150

^(d)

Quad Cities

Cordova, IL

75.00

Uranium

Base-load

1,380

^(d)

Salem

Hancock’s Bridge, NJ

42.59

Uranium

Base-load

1,004

^(d)

Three Mile Island

Londonderry Twp, PA

Uranium

Base-load

837

17,115

Fossil (Steam Turbines)^(e)

Conemaugh

New Florence, PA

20.72

Coal

Base-load

352

^(d)

Eddystone 3, 4

Eddystone, PA

Oil/Gas

Intermediate

760

Handley 4, 5

Fort Worth, TX

Gas

Peaking

870

Handley 3

Fort Worth, TX

Gas

Intermediate

395

Keystone

Shelocta, PA

20.99

Coal

Base-load

357

^(d)

Mountain Creek 6, 7

Dallas, TX

Gas

Peaking

240

Mountain Creek 8

Dallas, TX

Gas

Intermediate

565

Schuylkill

Philadelphia, PA

Oil

Peaking

166

Wolf Hollow 1, 2

Granbury, TX

Gas

Intermediate

425

Wolf Hollow 3

Granbury, TX

Gas

Intermediate

280

Wyman

Yarmouth, ME

5.89

Oil

Intermediate

^(d)

4,446

Fossil (Combustion Turbines)

Chester

Chester, PA

Oil

Peaking

Croydon

Bristol Twp., PA

Oil

Peaking

391

Delaware

Philadelphia, PA

Oil

Peaking

Eddystone

Eddystone, PA

Oil

Peaking

Falls

Falls Twp., PA

Oil

Peaking

Framingham

Framingham, MA

Oil

Peaking

LaPorte

Laporte, TX

Gas

Peaking

152

Medway

West Medway, MA

Oil/Gas

Peaking

105

Moser

Lower Pottsgrove Twp., PA

Oil

Peaking

New Boston

South Boston, MA

Oil

Peaking

Richmond

Philadelphia, PA

Oil

Peaking

Salem

Hancock’s Bridge, NJ

42.59

Oil

Peaking

^(d)

Schuylkill

Philadelphia, PA

Oil

Peaking

Southeast Chicago

Chicago, IL

Gas

Peaking

296

Southwark

Philadelphia, PA

Oil

Peaking

1,437

Exelon Generation – Total Electric Generating Capacity (continued)

Owned net electric generating capacity by station at December 31, 2011:

Station

Location

Number
of Units

Percent
Owned^(a)

Primary Fuel
Type

Primary
Dispatch Type

Net
Generation
Capacity^(b)
(MW)

Fossil (Internal Combustion/Diesel)

Conemaugh

New Florence, PA

20.72

Oil

Peaking

^(d)

Keystone

Shelocta, PA

20.99

Oil

Peaking

^(d)

Schuylkill

Philadelphia, PA

Oil

Peaking

Hydroelectric and Renewable

AgriWind

Bureau Co., IL

Wind

Base-load

^(d)

Blue Breezes

Faribault Co., MN

Wind

Base-load

Bluegrass Ridge

Gentry Co., MO

Wind

Base-load

^(d)

Brewster

Jackson Co., MN

94-99

Wind

Base-load

^(d)

Cassia

Twin Falls Co., ID

Wind

Base-load

Cisco

Jackson Co., MN

Wind

Base-load

^(d)

City Solar

Chicago, IL

n.a.

Solar

Base-load

Conception

Nodaway Co., MO

Wind

Base-load

Conowingo

Harford Co., MD

Hydroelectric

Base-load

572

Cow Branch

Atchinson Co., MO

Wind

Base-load

Cowell

Pipestone Co., MN

Wind

Base-load

^(d)

CP Windfarm

Faribault Co., MN

Wind

Base-load

Echo 1

Umatilla Co., OR

Wind

Base-load

^(d)

Echo 2

Morrow Co., OR

Wind

Base-load

Echo 3

Morrow Co., OR

Wind

Base-load

^(d)

Exelon Wind 1

Hansford Co., TX

Wind

Base-load

Exelon Wind 2

Hansford Co., TX

Wind

Base-load

Exelon Wind 3

Hansford Co., TX

Wind

Base-load

Exelon Wind 4

Hansford Co., TX

Wind

Base-load

Exelon Wind 5

Sherman Co., TX

Wind

Base-load

Exelon Wind 6

Sherman Co., TX

Wind

Base-load

Exelon Wind 7

Moore Co., TX

Wind

Base-load

Exelon Wind 8

Moore Co., TX

Wind

Base-load

Exelon Wind 9

Moore Co., TX

Wind

Base-load

Exelon Wind 10

Moore Co., TX

Wind

Base-load

Exelon Wind 11

Moore Co., TX

Wind

Base-load

Ewington

Jackson Co., MN

Wind

Base-load

^(d)

Fairless Hills

Falls Twp, PA

Landfill Gas

Peaking

Greensburg

Kiowa Co., KS

Wind

Base-load

Harvest

Huron Co., MI

Wind

Base-load

High Plains

Moore Co., TX

99.5

Wind

Base-load

^(d)

Loess Hills

Atchinson Co., MO

Wind

Base-load

Marshall

Lyon Co., MN

98-99

Wind

Base-load

^(d)

Michigan Wind 1

Bingham Twp., MI

Wind

Base-load

Michigan Wind 2

Bingham Twp., MI

Wind

Base-load

Mountain Home

Elmore Co., ID

Wind

Base-load

Muddy Run

Lancaster, PA

Hydroelectric

Intermediate

1,070

Norgaard

Lincoln Co., MN

Wind

Base-load

^(d)

Pennsbury

Falls Twp., PA

Landfill Gas

Peaking

Threemile Canyon

Morrow Co., OR

Wind

Base-load

Tuana Springs

Twin Falls Co., ID

Wind

Base-load

Wolf

Nobles Co., MN

Wind

Base-load

^(d)

2,539

Total

25,544

(a)	100%, unless otherwise indicated.

(b)	For nuclear stations, capacity reflects the annual mean rating. All other stations reflect a summer rating.

(c)	On December 8, 2010, Generation announced that it will permanently cease generation operation at Oyster Creek by December 31, 2019.

(d)	Net generation capacity is stated at proportionate ownership share.

(e)	Excludes Eddystone Generating Station Unit 2, which remained in operation presant to a reliability-must-run (RMR) agreement with PJM through May 31, 2012. Eddystone 2 ceased operations at the end of the RMR period.

Exelon Generation – Nuclear Generating Capacity

Exelon Nuclear Fleet^(a)(b)

(At December 31, 2011)

Station

Location
Water Body

Ownership

Owned Net
Capacity (MW)

2011
Generation (GWh)

Plant
Type

NSSS
Vendor

Braidwood

Braidwood, IL

100% Exelon

2,348

19,777

PWR

2 units

Kankakee River

Byron

Byron, IL

100% Exelon

2,323

18,203

PWR

2 units

Rock River

Clinton

Clinton, IL

100% Exelon

1,067

8,658

BWR

1 unit

Clinton Lake

Dresden

Morris, IL

100% Exelon

1,753

14,714

BWR

2 units

Kankakee River

LaSalle

Seneca, IL

100% Exelon

2,316

19,256

BWR

2 units

Illinois River

Limerick

Limerick Township, PA

100% Exelon

2,312

18,463

BWR

2 units

Schuylkill River

^(g)

Oyster Creek

Forked River, NJ

100% Exelon

625

5,298

BWR

1 unit

Barnegat Bay

Peach Bottom

Peach Bottom, PA

50% Exelon

1,150

9,412

BWR

2 units

Susquehanna River

50% PSEG Nuclear

Quad Cities

Cordova, IL

75% Exelon

1,380

11,401

BWR

2 units

Mississippi River

25% Mid-American

Energy Holdings

Salem

Hancock’s Bridge, NJ

42.6% Exelon

1,004

7,595

BWR

2 units

Deleware Estuary

57.4% PSEG Nuclear

Three Mile

Londonderry

100% Exelon

837

6,519

PWR

B&W

Island

Township, PA

1 unit

Susquehanna River

Total

17,115

139,297

Notes:

Amounts may not add due to rounding

Average in-service time = 31 years

PWR = Pressurized Water Reactor; BWR = Boiling Water Reactor

NSSS = Nuclear Steam Supply System

(a)	All stations are operated by Exelon Generation except Salem, which is operated by PSEG Nuclear, a division of Public Service Enterprise Group, Inc.

(b)	Owned Capacity and 2011 Generation are stated at Exelon’s ownership portion; unit summer rating is stated independent of ownership.

(c)	Open – a system that circulates water withdrawn from the environment, returning it to its source at a higher temperature. Closed – a system that recirculates cooling water with waste heat dissipated to the atmosphere through evaporation.

(d)	18-month refueling cycle.

(e)	24-month refueling cycle.

(f)	Dry cask storage will be in operation at all sites prior to the closing of spent fuel storage pools.

(g)	Supplemented with water from the Wadesville Mine Pool and the Still Creek Reservoir at Tamaqua via the Schuylkill River, and the Delaware Revier via the Bradshaw Reservoir at Perkiomen Creek.

(h)	On December 8, 2010, Generation announced that it will permanently cease generation operations at Oyster Creek by December 31, 2019.

Nuclear Operating Data^(a)


	2011			2010			2009
Fleet capacity factor		93.3	%		93.9	%		93.6	%
Fleet production cost per MWh	$	18.86		$	17.31		$	16.07

(a)	Excludes Salem, which is operated by PSEG.

Refueling Outages in 2011

•

Conducted 12 refueling outages-including Salem

•

Average refueling outage duration: 24 days

2011 Net Generation (excluding Salem): 131,701 MWh

Planned Refueling Outages (including Salem)


2010:	10 actual	2013: 10 planned
2011:	12 actual	2014: 11 planned
2012:	10 planned	2015: 11 planned

Exelon Generation – Nuclear Generating Capacity

Cooling Water

System^(c)

Unit/

Ownership

Annual Mean
Rating (MW)

Start of Commercial
Operations

Current License
Expiration

Last Refueling
Completed

Spent Fuel Pool
Capacity Reached^(f)

Braidwood

Closed

1/100%

1,190

1988

2026

May-12^(d)

Dry Cask Storage

(dedicated

2/100%

1,157

1988

2027

May-11^(d)

in operation

pond)

Closed

1/100%

1,174

1985

2024

Apr-11^(d)

Dry Cask Storage

Byron

2/100%

1,150

1987

2026

Oct-11^(d)

in operation

Closed

1/100%

1,067

1987

2026

Dec-11^(e)

2018

Clinton

Open

2/100%

880

1970

2029

Nov-11^(e)

Dry Cask Storage

Dresden

3/100%

872

1971

2031

Nov-10^(e)

in operation

Closed

1/100%

1,154

1984

2022

Mar-12^(e)

Dry Cask Storage

LaSalle

2/100%

1,162

1984

2023

Mar-11^(e)

in operation

Closed

1/100%

1,158

1986

2024

Mar-12^(e)

Dry Cask Storage

Limerick

2/100%

1,153

1990

2029

Apr-11^(e)

in operation

Open

1/100%

625

1969

2029^(h)

Dec-10^(e)

Dry Cask Storage

Oyster Creek

in operation

Open

2/50%

1,148

1974

2033

Oct-10^(e)

Dry Cask Storage

Peach Bottom

3/50%

1,152

1974

2034

Oct-11^(e)

in operation

Open

1/75%

903

1973

2032

Jun-11^(e)

Dry Cask Storage

Quad Cities

2/75%

937

1973

2032

Apr-12^(e)

in operation

Closed

1/42.6%

1,181

1977

2036

Nov-11^(d)

Dry Cask Storage

Salem

2/42.6%

1,176

1981

2040

May-11^(d)

in operation

Closed

1/100%

837

1974

2034

Nov-11^(e)

2023

Three Mile Island

Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary

Owned generation as of December 31, 2011. Table does not include station auxiliary equipment or plants comprised solely of peaking combustion turbines.


			Net Generation Available for Sale (GWh)
	Capacity(a)
Fossil Station (Location) / Water Body	(MW)		2011		2010		2009
Conemaugh (New Florence, PA) / Conemaugh River		352		2,240		2,519		2,517
Units: 2 coal units (baseload)
Data reflects Exelon Generation’s 20.72% plant ownership.

Cromby^(b)(Phoenixville, PA) / Schuylkill River		345		151		564		524
Units: 1 coal unit (intermediate), 1 oil/gas steam unit (intermediate)

Eddystone^(c)(Eddystone, PA) / Delaware River		1,408		427		2,033		2,041
Units: 2 coal units (intermediate), 2 oil/gas steam units (intermediate),
4 combustion turbines (peaking)

Fairless Hills (Falls Township, PA) / Delaware River		60		242		239		237
Units: 2 landfill gas units (peaking)

Handley (Ft. Worth, TX) / Lake Arlington		1,265		585		362		523
Units: 3 gas steam units (2 peaking/1 intermediate)

Keystone (Shelocta, PA) / Keystone Lake		357		2,346		2,844		2,212
Units: 2 coal units (baseload)
Data reflects Exelon Generation’s 20.99% plant ownership.

Mountain Creek (Dallas, TX) / Mountain Creek cooling pond		805		627		726		689
Units: 3 gas steam units (2 peaking/1 intermediate)

Schuylkill (Philadelphia, PA) / Schuylkill River		196		6		8		9
Units: 1 oil steam unit (peaking)

Wolf Hollow^(d)(Granbury, TX) / Lake Granbury		705		654
Units: 2 gas combined cycle turbines and 1 steam generator (intermediate)

(a)	Capacity reflects summer rating and is reported at ownership portion.

(b)	Cromby Unit 1 (coal) was retired on May 31, 2011; Cromby Unit 2 (oil/gas steam) was retired on Dec 31, 2011. Retired unit capacity is included in plant totals.

(c)	Eddystone Unit 1 (coal) was retired on May 31, 2011; Eddystone Unit 2 (coal) was retired on May 31, 2012. Retired unit capacity is included in plant totals.

(d)	Wolf Hollow generating station was acquired effective August 25, 2011; no data prior to the acquisition are included.

Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary


Emissions (thousand tons)							Reduction Technology
										Post			Low NOx
										combustion			burners with			Induced			Cooling
							SO2			NOx controls			separated			flue gas			Water
Type	2011		2010		2009		Scrubber			(SCR or SNCR)			overfire air			recirculation			System
Conemaugh
SO2		1.5		1.5		1.5		X
NOx		3.6		4.0		3.9								X
CO2		2,218.7		2,488.2		2,486.0														Closed

Cromby
SO2		0.8		2.1		2.2		X
NOx		0.4		1.3		1.1		(Coal Unit	)		X			X
CO2		243.2		680.6		615.0					(Coal Unit	)		(Coal Unit	)					Open

Eddystone
SO2		0.9		4.9		5.3		X
NOx		0.8		3.8		3.8		(Coal Units	)		X			X
CO2		576.7		2,749.8		2,754.7					(Coal Units	)		(Coal Units	)					Open

Fairless Hills
SO2		0.1		0.1		0.1
NOx		0.1		0.1		0.1
CO2		207.7		201.1		226.0														Open

Handley
SO2		*		*		*
NOx		0.1		*		*					X
CO2		422.2		263.8		377.0														Open

Keystone
SO2		9.7		8.2		23.7
NOx		4.4		1.2		0.8		X			X			X
CO2		2,383.2		2,803.3		2,146.2														Closed

Mountain Creek
SO2		*		*		*
NOx		0.1		0.1		0.1					X						X
CO2		457.1		488.6		470.5					(Unit 8	)					(Units 6, 7	)		Open

Schuylkill
SO2		*		*		*
NOx		*		*		*
CO2		15.2		15.5		14.3														Open

Wolf Hollow
SO2		*
NOx		0.1
CO2		330.4																		Open

*	Indicates emissions less than 50 tons.

Constellation Energy – Total Owned Generating Capacity

Generating capacity by facility at December 31, 2011:


Plant	Location	2011 Capacity Factor (%)^(a)		Primary Fuel	Capacity (MW)^(b)		% Owned		Owned Capacity (MW)
Nuclear
Calvert Cliffs Unit 1^(c)	Calvert Co., MD		100.9	Uranium		855		50		428
Calvert Cliffs Unit 2^(c)	Calvert Co., MD		91.7	Uranium		850		50		425
Nine Mile Point Unit 1^(c)	Scriba, NY		84	Uranium		628		50		314
Nine Mile Point Unit 2^(c)(d)	Scriba, NY		95.4	Uranium		1,141		41		468
R.E. Ginna^(c)	Ontario, NY		84.7	Uranium		581		50		291

						4,055				1,925

Fossil
ACE	Trona, CA		87.5	Coal		102		31.1		32
Brandon Shores^(e)	Anne Arundel Co., MD		52.6	Coal		1,273		100		1,273
C. P. Crane^(e)	Baltimore Co., MD		27.8	Oil/Coal		399		100		399
Colorado Bend Energy Center	Wharton TX		31.6	Gas		550		100		550
Colver	Colver Township, PA		99.8	Waste Coal		102		25		26
Conemaugh	West Moreland Co., PA		71.5	Coal		1,711		10.6		181	^(f)
Fore River	North Weymouth, MA		79.3	Gas		688		100		688
Gould Street	Baltimore City, MD		2.5	Gas		97		100		97
Grande Prairie	Alberta, Canada		20.6	Gas		93		100		93
H. A. Wagner^(e)	Anne Arundel Co., MD		18	Coal/Oil/Gas		976		100		976
Handsome	Lake Rockland Twp, PA		1.9	Gas		268		100		268
Hillabee Energy Center	Alexander City, AL		64.3	Gas		740		100		740
Jasmin	Kern Co., CA		94.9	Coal		35		50		18
Keystone	Armstrong & Indiana Cos., PA		74	Coal		1,711		21		359	^(f)
Mystic 7	Charlestown, MA		2	Oil/Gas		560		100		560
Mystic 8	Charlestown, MA		75.8	Gas		703		100		703
Mystic 9	Charlestown, MA		74.8	Gas		695		100		695
Mystic Jet	Charlestown, MA		0.1	Oil		9		100		9
Notch Cliff	Baltimore Co., MD		2.3	Gas		101		100		101
Panther Creek	Nesquehoning, PA		98	Waste Coal		80		50		40
Perryman	Harford Co., MD		2	Oil/Gas		347		100		347
Philadelphia Road	Baltimore Co., MD		0.8	Oil		61		100		61
POSO	Kern Co., CA		73.6	Coal		35		50		18
Quail Run Energy Center	Odessa, TX		14.1	Gas		550		100		550
Riverside	Baltimore Co., MD		1	Oil/Gas		228		100		228
Sunnyside	Sunnyside, UT		93.6	Waste Coal		51		50		26
West Valley	Salt Lake City, UT		10.3	Gas		200		100		200
Westport	Baltimore Co., MD		0	Gas		116		100		116

						12,481				9,351

Constellation Energy – Total Owned Generating Capacity (continued)


Hydroelectric and Renewable
Chinese Station	Jamestown, CA	70.7	Biomass	22	45	10
Fresno	Fresno, CA	91.9	Biomass	24	50	12
Rocklin	Placer Co., CA	86.7	Biomass	24	50	12
Malacha	Muck Valley, CA	37.4	Hydroelectric	32	50	16
Safe Harbor	Safe Harbor, PA	44.9	Hydroelectric	417	66.7	278
Constellation Solar^(g)	Various	—	Solar	69	100	69
SEGS IV	Kramer Junction, CA	26	Solar	33	12.2	4
SEGS V	Kramer Junction, CA	37.8	Solar	24	4.2	1
SEGS VI	Kramer Junction, CA	28.1	Solar	34	8.8	3
Criterion	Oakland, MD	32.4	Wind	70	100	70

				749		475

Total				17,294		11,751

Note: The sums of the individual plant capacities may not equal the category or overall totals due to rounding.

(a)	Capacity factors are based on installed capacity, which is temperature adjusted. Therefore, it is possible to generate more than 100% of the installed capacity.

(b)	Capacity figures represent summer seasonal claimed capacity amounts. For units with power purchase agreements, figures represent contract capacity.

(c)	Constellation has a 50.01% equity membership interest in CENG, the joint venture with EDF that holds these nuclear generating assets.

(d)	CENG owns 82% of Nine Mile Point Unit 2, the remaining interest in which is owned by Long Island Power Authority. CENG owns 100% of all other nuclear units listed.

(e)	Coal assets divested in 2012 as part of the merger agreement.

(f)	Reflects Constellation’s proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of diesel. Capacity for Keystone and 1 MW of diesel capacity for Conemaugh.

(g)	Constellation Solar is an operation that constructs, owns, and operates solar facilities at various customer locations.

Constellation Energy – Nuclear Generating Capacity

CENG Fleet

Constellation Energy Nuclear Group (CENG) is a Maryland limited liability company whose members are Constellation Energy Group, Inc (50.01% interest) and EDF, Inc. (49.99% interest). CENG owns and operates five nuclear power reactors on three sites.

(At December 31, 2011)

Station

Location

Water Body

Plant Ownership

Owned Net
Capacity (MW)^(a)

2011
Generation (GWh)^(a)

Plant
Type

Calvert Cliffs

Lusby, MD

50.01% Constellation

853

7,200

PWR

2 units

Chesapeake Bay

49.99% EDF

Nine Mile Point

Scriba, NY

44.20% Constellation^(e)

782

6,221

BWR

2 units

Lake Erie

44.19% EDF^(e)

11.61% LIPA^(e)

R.E. Ginna

Ontario, NY

50.01% Constellation

291

2,148

PWR

1 unit

Lake Erie

49.99% EDF

Total

1,925

15,569

Note:

Amounts may not add due to rounding

PWR = Pressurized Water Reactor; BWR = Boiling Water Reactor

(a)	Owned Capacity and 2011 Generation are stated at Constellation Energy’s ownership portion. Summer unit rating is stated independent of ownership.

(b)	Open – a system that circulates water withdrawn from the environment, returning it to its source at a higher temperature. Closed – a system that recirculates cooling water with waste heat dissipated to the atmosphere through evaporation.

(c)	On-site Independent Spent Fuel Storage Installation (IFSI) will be in operation at all sites prior to the closing of spent fuel storage pools.

(d)	24-month refueling cycle

(e)	CENG owns 100% of Nine Mile Point Unit 1 and 82% of Nine Mile Point Unit 2. The remaining interest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority (LIPA)

(f)	18-month refueling cycle.

Nuclear Operating Data


	2011			2010			2009
Fleet capacity factor		92.3	%		94.0	%		95.7	%
Fleet production cost per MWh	$	25.35		$	21.33		$	20.86

Refueling Outages in 2011

– Conducted 3 refueling outages

Planned Refueling Outages


2010:	2 actual	2013: 2 planned
2011:	3 actual	2014: 3 planned
2012:	3 planned	2015: 3 planned

Constellation Energy Nuclear Group Fleet


	Cooling Water System^(b)		Unit/CEG Ownership			Summer Rating (MW)^(a)		Start of Commercial Operations		Current License Expiration		Last Refueling Completed	Spent Fuel Pool Capacity Reached^(c)
Calvert Cliffs		Open		1/50.01	%		855		1975		2034	Apr-12^(d)	ISFSI in operation
				2/50.01	%		850		1977		2036	Mar-11^(d)

Nine Mile		Open/		1/50.01	%		628		1970		2029	Apr-11^(d)	Fuel pool not full;
Point		Closed		2/41.01	%		1,141		1988		2046	Jun-12^(d)	ISFSI under

R.E. Ginna		Open		1/50.01	%		581		1970		2029	Jun-11^(f)	ISFSI in operation

Constellation Energy – Fossil Emissions and Emission Reduction Technology Summary

Owned generation as of December 31, 2011. Table does not include station auxiliary equipment or plants comprised soley of peaking combustion turbines.


			Net Generation Available for Sale (GWh)
	Capacity^(a)
Fossil Station (Location) / Water Body	(MW)		2011		2010		2009
Brandon Shores^(b)(Baltimore, MD) / Patapsco River		1,273		5,868		6,032		6,614
Units: 2 coal units (baseload)

C.P. Crane^(b)(Baltimore, MD) / Seneca Creek		399		970		845		1,063
Units: 2 coal units (intermediate) & 1 oil combustion turbine (peaking)

Colorado Bend Energy Center (Wharton, TX) / Colorado River		550		1,524		819
Units: 4 2x1 CCGTs & 2 steam generators (intermediate)

Conemaugh (New Florence, PA) / Conemaugh River		181		1,131		1,284		1,283
Units: 2 coal units (baseload)
Data reflects Constellation’s 10.6% ownership

Fore River (North Weymouth, MA) / Town River		688		4,781
Units: 4 2x1 CCGTs & 3 steam generators (intermediate)

Gould Street (Baltimore MD) / Patapsco River		97		21		22		7
Units: 1 gas steam unit (intermediate)

H.A. Wagner^(b)(Baltimore, MD) / Patapsco River		976		1,538		1,644		2,293
Units: 1 oil/gas steam unit, 2 coal units, 1 oil steam unit, & 1 oil combustion turbine (intermediate)

Hillabee Energy Center (Alexander City, AL) / Municipal Supply		740		4,166		2,389
Units: 2 2x1 CCGTs & 1 steam generator (intermediate)

(a)	Capacity reflects summer rating and is reported at ownership portion.

(b)	Constellation’s Baltimore coal plants were divested in 2012 according to the terms of the merger agreement with the state of Maryland.

Constellation Energy – Fossil Emissions and Emission Reduction Technology Summary


Emissions (thousand tons)							Technology
								Cooling
								Water
Type	2011		2010		2009		Air Pollution Control	System
Brandon Shores
SO2		2.8		1.3		32.8	SCR, ESP, activated carbon, injection,
NOx		4.8		3.8		3.5	baghouse, overfire air, low-NOx burners,
CO2		6,610		6,330		6,861	FGD, hydrated lime injection		Closed

C.P. Crane
SO2		5.7		5.6		12.5	baghouse, overfire air, (natural gas
NOx		2.5		2.5		2.1	reburn capability), SNCR, activated
CO2		1,242		1,050		1,216	carbon injection		Open

Colorado Bend
SO2		*		*
NOx		0.1		3.1
CO2		759		513			SCR, low-NOx burners		Closed

Conemaugh
SO2		0.8		0.7		0.8
NOx		1.9		2.0		2.0
CO2		1,131		1,273		1,267	ESP, FGD, low-NOx burners		Closed

Fore River
SO2		*
NOx		0.1
CO2		2,018					SCR, low-NOx burners		Open

Gould Street
SO2		*		*		*
NOx		*		*		*
CO2		17		18		6	low-NOx burners		Open

H.A. Wagner
SO2		9.1		9.2		15.1
NOx		1.7		1.5		1.7	ESP, SNCR, low-NOX burners,
CO2		1,760		1,820		2,401	activated carbon injection, multicyclones		Open
Hillabee Energy Ctr.
SO2		*		*
NOx		0.1		0.1
CO2		1,786		1,020			SCR		Closed

*	Indicates emissions less than 50 tons.

(Continued on next page)

Constellation Energy – Fossil Emissions and Emission Reduction Technology Summary (continued)

Owned generation as of December 31, 2011. Table does not include station auxiliary equipment or plants comprised soley of peaking combustion turbines.


			Net Generation Available for Sale (GWh)
Fossil Station (Location) / Water Body	Capacity^(a) (MW)		2011		2010		2009
Keystone (Shelocta, PA) / Keystone Lake		359		2,329		2,845		2,213
Units: 2 coal units (baseload)
Data reflects Constellation’s 21.0% ownership

Mystic & Mystic Jet (Charlestown, MA) / Mystic River		1,967		9,324
Units: 4 2x1 CCGT, 3 steam generators & 1 combustion turbine (intermediate)

Panther Creek (Nesquehoning, PA)		40		343		338		338
4th Hollow Reservoir & Lausanne Mine Pool
Units: 1 waste coal unit (baseload)
Data reflects Constellation’s 50.0% plant ownership

Quail Run Energy Center (Odessa, TX) / Municipal		550		681		736
Units: 4 2x1 CCGT & 2 steam generators (intermediate)

Riverside (Baltimore, MD) / Patapsco River		228		20		13		1
Units: 1 gas steam unit & 3 gas/oil combustion turbines (peaking)

(a)	Capacity reflects summer rating and is reported at ownership portion.

(b)	Constellation’s Baltimore coal plants were divested in 2012 according to the terms of the merger agreement with the state of Maryland.

Constellation Energy – Fossil Emissions and Emission Reduction Technology Summary (continued)

Emissions (thousand tons)

Technology

Water

Type

2011

2010

2009

Air Pollution Control

System

Keystone

SO2

9.8

8.2

23.7

NOx

4.4

1.2

0.8

CO2

2,383

2,805

2,152

ESP, SCR, FGD

Closed

Mystic & Mystic Jet

SO2

NOx

0.3

CO2

4,102

SCR, low-NOx burners

Open

Panther Creek

SO2

0.3

NOx

0.3

SNCR, limestone and

CO2

568

474

453

ammonia injection, baghouse

Closed

Quail Run Energy Cnt.

SO2

NOx

0.1

CO2

398

360

SCR, low-NOx burners

Closed

Riverside

SO2

NOx

CO2

low-NOx burners

Open

*	Indicates emissions less than 50 tons.

Exelon Corporation

10 South Dearborn Street, 52nd Floor

Chicago, IL 60603

EXELON GENERATION CO LLC - FORM 8-K - EX-99.1 - 2011 FACT BOOK - September 24, 2012

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