Peco Energy 8-K Regulation FD Disclosure

Exhibit 99.1

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 2012 Generation Fuel Mix Exelon	4
Generation Capacity	5
Credit and Liquidity for Exelon and Operating Companies
Credit Ratings, Credit Facilities and Commercial Paper	5
Long Term Debt Outstanding as of December 31, 2012
Exelon Corporation	6
Exelon Generation	6
ComEd	7
PECO	8
BGE	9
Federal Regulation
Federal Energy Regulatory Commission (FERC), ComEd Electric Transmission Rate Cases, BGE Electric Transmission Rate Cases	10
State Regulation
Illinois Commerce Commission (ICC), ComEd Electric Distribution Rate Cases and Average Residential Rate	11, 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
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP
Consolidated Statements of Operations
Exelon Corporation	16
Exelon Generation	17
ComEd	18
PECO	19
BGE	20
Supply and Sales Statistics
Exelon Generation – Annual Electric Supply and Sales Statistics	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	26-29
Exelon Nuclear Fleet and Nuclear Operating Data	30-31
Fossil Emissions and Emission Reduction Technology Summary	32-35
Exelon Generation – Total Contracted Generation Capacity	36

To the Financial Community,

The Exelon Fact Book provides historical financial and operating information to assist in the analysis of Exelon and its operating companies. Please refer to the SEC filings of Exelon and its subsidiaries, including the annual Form 10-K and quarterly Form 10-Q, for more comprehensive financial statements and information.

For more information about Exelon or to send e-mail inquiries, visit 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

Information in this Fact Book is current as of December 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 those discussed in (1) Exelon’s 2012 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 19; and (2) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of 12/31/12. None of the Registrants undertakes any obligation to publicly release any revisions to its forward-looking statements to reflect events or circumstances after the date of this publication.

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 one of the largest competitive U.S. power generators, with approximately 35,000 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 2012
$23.5 billion in operating revenues $78.5 billion in assets 6.6 million electric customers 1.2 million gas customers	~26,000 employees 7,350 circuit miles of electric transmission lines ~35,000 MW U.S. generating capacity	~165 terawatt-hours of electric load served 415 billion cubic feet of natural gas served $2.10 annual dividend rate per share(a)

(a) Exelon’s Board of Directors declared the first quarter 2013 dividend of $0.525 per share and approved a revised dividend policy going forward. The first quarter dividend is based on our previous level of $2.10 per share on an annualized basis, while the new dividend contemplates a regular $0.31 per share quarterly dividend beginning in the second quarter of 2013 (or $1.24 per share on an annualized basis). Exelon intends to maintain the normal cadence of quarterly dividend declarations by the Board, so the Board will take formal action to declare the next dividend in the second quarter.

        2

Exelon Generation is one of the largest competitive power generators in the nation, with owned generating assets totaling approximately 35,000 megawatts. With strong positions in the Midwest, Mid-Atlantic and Texas, 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 approximately 100,000 business and public sector customers, 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 more than 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 655,000 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 497,000 natural gas customers.

3        

Exelon Service Area and Selected Generation Assets as of December 31, 2012

        4

Credit Ratings as of February 28, 2013

	Moody’s Investors Service	(a)	Standard & Poor’s Corporation	(b)	Fitch Ratings	(c)
Exelon Corporation
Senior Unsecured Debt	Baa2		BBB	-	BBB	+
Commercial Paper	P2		A2		F2
Exelon Generation
Senior Unsecured Debt	Baa2		BBB		BBB	+
Commercial Paper	P2		A2		F2
BGE
Senior Secured Debt	A2		N/A		A	-
Senior Unsecured Debt	Baa1		BBB	+	BBB	+
Commercial Paper	P2		A2		F2
ComEd
Senior Secured Debt	A3		A	-	BBB	+
Senior Unsecured Debt	Baa2		BBB		BBB
Commercial Paper	P2		A2		F3
PECO
Senior Secured Debt	A1		A	-	A
Senior Unsecured Debt	A3		N/A		A	-
Commercial Paper	P2		A2		F2

(a) On February 7, 2013, Moody’s affirmed the issuer rating and senior unsecured ratings of Exelon at Baa2 and downgraded Exelon Generation’s issuer rating and senior unsecured rating to Baa2 from Baa1. The outlook for both is stable. Utility ratings were unaffected.

(b) All ratings at S&P have a stable outlook.

(c) On February 8, 2013, Fitch affirmed the issuer default ratings and instrument ratings of Exelon and all its subsidiaries. Additionally, Fitch placed ComEd on positive outlook. All other outlooks are stable.

Credit Facilities and Commercial Paper as of February 28, 2013

	BGE		ComEd			PECO			Generation			Exelon Corporate			Total
(in millions)
Unsecured Revolving Credit Facilities(a)		$600		$1,000			$600			$5,675			$500			$8,375
Outstanding Facility Draws		–		–			–			–			–			–
Outstanding Letters of Credit		–		–			(1	)		(1,682	)		(2	)		(1,685	)
Available Capacity under Facilities(b)		600		1,000			599			3,993			498			6,690
Outstanding Commercial Paper		–		(93	)		–			–			–			(93	)
Available Capacity less Outstanding Comm. Paper		$600		$907			$599			$3,993			$498			$6,597

(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.

5        

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								21		–		21
BGE Debt Fair Value Adjustment(a)								249		–		249
Total Long-Term Debt								$1,570		$–		$1,570
Maturities		2013		2014		2015		2016		2017
		–		–		$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		788		–		788
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		258		–		258
CEG Senior Notes(a)		8.625%		6/27/08		6/15/63		450		–		450
Exelon Wind		2.00%		12/10/10		7/31/17		2		–		2
Total Senior Notes								$6,721		$–		$6,721
Non Regulated Business
Pollution Control Loan(b)		4.10%		12/20/84		7/1/14		$20		$20		$–
Solar Revolver		1.96%		7/7/11		7/7/14		113		–		113
CEU Credit Agreement		2.21%		7/22/11		7/22/16		72		–		72
Clean Horizons Solar Term Loan Agreement		2.56%		9/7/12		9/7/30		38		2		36
Sacramento PV Energy Loan Agreement		2.77%		7/26/11		12/31/30		39		3		36
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-Draws		2.33%–3.09%		various		1/5/37		220		–		220
Total Non Regulated Business								$520		$25		$495
Notes Payable
Capital Leases								$30		$3		$27
Unamortized Debt Discount & Premium, Fair Value Amortization, Net								13		–		13
CEG Senior Notes Fair Market Value Adjustment								199		–		199
Total Long-Term Debt								$7,483		$28		$7,455
Maturities		2013		2014		2015		2016		2017
		$28		$616		$553		$76		$706

(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.

        6

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		253			–		253
103		5.90%		3/6/06		3/15/36		625			–		625
107		6.45%		1/16/08		1/15/38		450			–		450
113		3.80%		10/1/12		10/1/42		350			–		350
Total First Mortgage Bonds								$5,447			$252		$5,195
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								(20	)		–		(20	)
Total Long-Term Debt								$5,773			$252		$5,521
Note: Amounts may not add due to rounding.
Maturities		2013		2014		2015		2016			2017
		$252		$617		$260		$665			$425

7        

PECO

Series	Interest Rate		Date           Issued		Maturity Date		Total Debt         Outstanding			Current Portion		Long-Term Debt
(in millions)
First Mortgage Bonds (FMB)
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		2.38%		9/17/12		9/15/22		350			–		350
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								$1,950			$300		$1,650
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								(3	)		–		(3	)
Total Long-Term Debt								$2,131			$300		$1,831
Maturities		2013		2014		2015		2016			2017
		$300		$250		–		–			–

        8

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 8/15/22		2.80%		8/17/12		8/15/22		250			–		250
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								$1,850			$400		$1,450
Rate Stabilization Bonds
BGE Securitization due 2017		5.72%–5.82%		6/28/07		4/1/17		$332			$67		$265
Total Rate Stabilization Bonds								$332			$67		$265
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								(4	)		–		(4	)
Total Long-Term Debt								$2,436			$467		$1,969
Maturities		2013		2014		2015		2016			2017
		$467		$70		$75		$379			$41

9        

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)(d)	4/29/13	$68	2012 pro forma	$2,184	8.70%	11.50%	55%
ComEd Update(a)	5/15/12	$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 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.

(d) Revenue requirement increase primarily reflects increased transmission O&M, A&G costs, plant additions, and an increased true up adjustment.

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)(c)	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.

(c) On February 27, 2013, state regulators and consumer advocates (including the MD PSC) filed a complaint against four mid-Atlantic electric utilities (including BGE) seeking a FERC order to reduce the base return equity used in the utilities’ formula transmission rates and directing the utilities to submit compliance filings to implement certain changes to the formula transmission rate implementation protocols.

        10

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
Miguel del Valle (Acting)	Democrat	2/13	1/18	City Clerk of Chicago; First Hispanic elected to Illinois State Senate; Co-founder of the Illinois Association of Hispanic State Employees and the Illinois Latino Advisory Council on Higher Education; Vice Chairman of the Illinois Student Assistance Commission
Sherina Maye (Acting)	Independent	2/13	1/18	Associate in Chicago office of Locke Lord LLP; Mentor at the Young Women’s Leadership Charter School; a Founding Board Member of the Great Lakes Academy Charter School; Associate Board Member for the Chicago Committee for Minorities in Large Law Firms
John T. Colgan	Democrat	11/09	1/15	Member of Illinois Association of Community Action Agencies; executive director of the Illinois Hunger Coalition

11        

ComEd Electric Distribution Rate Cases

($ in millions)	Revenue Date			Increase			Test Year		Overall Rate Base		Rate of Return		Equity		Equity Ratio
Formula Rate Filing(e)		4/29/13	(f)		$311			2012		$6,731		7.01%		8.72%		44.99%
Formula Rate Filing(e)		4/30/12			$74			2011		$6,367		7.58%		9.81%		42.55%
ICC Order(e)		12/19/12			$73			2011		$6,367		7.58%		9.81%		42.55%
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%
ICC Order on Rehearing		10/3/12			($133	)		2010		$6,188		8.16%		10.05%		46.17%
ComEd Request(b)		6/30/10			$343			2009		$7,349		8.98%		11.50%		47.28%
ICC Order		5/24/11			$143			2009		$6,549		8.51%		10.50%		47.28%
ComEd Request(c)		10/17/07			$345			2006		$6,753		8.57%		10.75%		45.04%
ICC Order(d)		9/10/08			$274			2006		$6,694		8.36%		10.30%		45.04%

(a) On June 22, 2012 the ICC granted expedited rehearing in Docket 11-0721 on three aspects of the formula rate order. On October 3, 2012, the ICC issued its final order (Rehearing Order) in that rehearing, adopting ComEd’s position on the return on its pension asset, resulting in an increase in ComEd’s overall annual revenue requirement.

(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. ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case until June 1, 2011, when the rates set in the 2010 Rate Case became effective. On February 23, 2012, the ICC issued an order on remand reflecting that ComEd should provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation. On March 26, 2012, ComEd filed a notice of appeal with the Court.

(e) Reflects ComEd’s October 11 Compliance filing in Docket 12-0321 including the impacts of the May and October 2012 orders in the initial formula case. Rate base reflects filing year amounts. Rate of Return, Return on Equity, and Equity Ratio reflect the reconciliation year amounts.

(f) Reflects ComEd’s initial filing on April 29, 2013. Rate of Return on Equity and Equity Ratio reflect the reconciliation year amounts.

ComEd – Average Total Residential Rate

($/MWh)
Year	Transmission		Distribution		Energy		Other(a)		Total
2010		$6.80		38.71		72.81		3.34		121.66
2011		$7.49		41.40		73.14		3.78		125.80
2012		$5.98		36.12		53.51		10.86		106.47

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

        12

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
2012	8.04	59.95	2.42	–		88.52	158.93

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

13        

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
W. Kevin Hughes (Chairman)	Democrat	9/11	6/13	Attorney; Deputy Legislative Officer to Governors O’Malley, Glendening; Legislative Officer under Governor Schaefer; Principal Analyst for MD Department of Legislative Services
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
Vacant	TBD	TBD	TBD	TBD

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	$130	2011-12	$2,710	7.96%	10.5%	48.4%
PSC Order	2/22/13	$81	2011-12	$2,635	7.60%	9.75%	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	$46	2011-12	$1,014	7.96%	10.5%	48.4%
PSC Order	2/22/13	$32	2011-12	$976	7.53%	9.60%	48.4%
BGE Request	5/7/10	$30	2009-10	$839	8.99%	11.65%	51.93%
PSC Order	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
2012	85.54	7.87	33.35	4.78		131.54

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

        14

(at December 31)	2012			2011			2010
Exelon (consolidated)		(in millions)	(in percent)		(in millions)	(in percent)		(in millions)	(in percent)
Total Debt		$19,603	47.3		$13,405	48.1		$12,828	48.4
Preferred Securities of Subsidiaries		87	0.2		87	0.3		87	0.3
Total Equity		21,730	52.5		14,388	51.6		13,563	51.2
Total Capitalization		$41,420			$27,880			$26,478
Transition Debt					$–			$–
Exelon Generation
Total Debt		$7,483	37.1		$3,679	29.7		$3,679	33.9
Total Equity		12,665	62.9		8,708	70.3		7,177	66.1
Total Capitalization		$20,148			$12,387			$10,856
ComEd
Total Debt		$5,773	44.1		$5,871	45.5		$5,207	43.0
Total Shareholders’ Equity		7,323	55.9		7,037	54.5		6,910	57.0
Total Capitalization		$13,096			$12,908			$12,117
PECO
Total Debt(a)		$2,341	43.3		$2,381	44.0		$2,631	47.0
Preferred Securities(b)		87	1.6		87	1.6		87	1.6
Total Shareholders’ Equity		2,982	55.1		2,938	54.3		2,883	51.5
Total Capitalization		$5,410			$5,406			$5,601
Transition Debt					$–			$–
BGE(c)
Total Debt		$2,436	50.8		n/a	n/a		n/a	n/a
Preferred Securities		190	4.0		n/a	n/a		n/a	n/a
Total Shareholders’ Equity		2,168	45.2		n/a	n/a		n/a	n/a
Total Capitalization		$4,794			n/a			n/a

Note: Percentages may not add due to rounding.

(a) Includes PECO’s accounts receivable agreement at December 31, 2012, 2011 and 2010 of $210 million, $225 million and $225 million, respectively, which is classified as a short-term note payable.

(b) On March 25, 2013, PECO Energy Company (PECO) issued a press release announcing that it had issued a notice of redemption for all of the outstanding shares of its preferred stock, effective May 1, 2013.

(c) BGE was not part of Exelon in 2010 and 2011.

15        

Exelon Generation

	Twelve Months Ended December 31, 2012(a)								Twelve Months Ended December 31, 2011
						Adjusted								Adjusted
(in millions)		GAAP	(b)	Adjustments			Non-GAAP			GAAP	(b)	Adjustments			Non-GAAPP
Operating revenues		$14,437		$1,065	(c),(d),(e)		$15,502			$10,447		$(66	)(c),(o)		$10,381
Operating expenses
Purchased power and fuel		7,061		607	(c),(d),(e),(f)		7,668			3,589		(292	)(c),(d)		3,297
Operating and maintenance		5,028		(889	)(c),(e),(f),(g)   (h),(l),(m),(n)		4,139			3,148		(77	)(c),(f),(g),(l),(o)		3,071
Depreciation, amortization, accretion and depletion		768		(47	)(c),(f)		721			570		(87	)(c)		483
Taxes other than income		369		(11	)(c)		358			264		(1	)(d)		263
Total operating expenses		13,226		(340	)		12,886			7,571		(457	)		7,114
Equity in earnings of unconsolidated affiliates		(91	)	150	(e),(f)		59			(1	)	–			(1	)
Operating income		1,120		1,555			2,675			2,875		391			3,266
Other income and deductions
Interest expense		(301	)	(16	)(i)		(317	)		(170	)	–			(170	)
Loss in equity method investments		–		–			–			–		–			–
Other, net		239		(94	)(c),(f),(j)		145			122		(21	)(j),(o)		101
Total other income and deductions		(62	)	(110	)		(172	)		(48	)	(21	)		(69	)
Income before income taxes		1,058		1,445			2,503			2,827		370			3,197
Income taxes		500		459	(c),(d),(e),(f),(g),(h),  (i),(j),(k),(l),(m),(n)		959			1,056		139	(c),(d),(f),(g),(j)  (k),(l),(o)		1,195
Net Income		558		986			1,544			1,771		231			2,002
Net loss attributable to noncontrolling interests		(4	)	–			(4	)		–		–			–
Net income on common stock		$      562		$      986			$  1,548			$  1,771		$  231			$  2,002

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger.

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(g) Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units in 2011 and 2012, and a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012.

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(i) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(j) Adjustment to exclude the unrealized gains in 2011 for the three months ended, unrealized losses in 2011 for the twelve months ended and unrealized gains in 2012 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(k) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger for 2012 and as a result of revised estimates of state apportionments for 2011.

(l) Adjustment to exclude certain costs associated with various acquisitions.

(m) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(n) Adjustment to exclude costs associated with the March 2012 settlement with the FERC.

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

17        

ComEd

	Twelve Months Ended December 31, 2012								Twelve Months Ended December 31, 2011
						Adjusted								Adjusted
(in millions)		GAAP	(a)	Adjustments			Non-GAAP			GAAP	(a)	Adjustments			Non-GAAPP
Operating revenues		$5,443		$  –			$5,443			$6,056		$      –			$6,056
Operating expenses
Purchased power		2,307		–			2,307			3,035		–			3,035
Operating and maintenance		1,345		(5	)(b)		1,340			1,189		13	(c)		1,202
Depreciation, amortization		610		–			610			554		–			554
Taxes other than income		295		–			295			296		–			296
Total operating expenses		4,557		(5	)		4,552			5,074		13			5,087
Operating income		886		5			891			982		(13	)		969
Other income and deductions
Interest expense		(307	)	–			(307	)		(345	)	–			(345	)
Other, net		39		–			39			29		–			29
Total other income and deductions		(268	)	–			(268	)		(316	)	–			(316	)
Income before income taxes		618		5			623			666		(13	)		653
Income taxes		239		3	(b)		242			250		–	(c),(d)		250
Net income		$    379		$  2			$    381			$    416		$(13	)		$    403

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(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.

        18

BGE

	March 12, 2012 through December 31, 2012
(in millions)		GAAP	(a)	Adjustments		Adjusted Non-GAAPP
Operating revenues		$2,091		$113	(c)	$2,204
Operating expenses
Purchased power and fuel		1,052		–		1,052
Operating and maintenance		596		(37	)(b),(c)	559
Depreciation, amortization		238		–		238
Taxes other than income		167		2	(c)	169
Total operating expenses		2,053		(35	)	2,018
Operating income		38		148		186
Other income and deductions
Interest expense		(111	)	–		(111	)
Other, net		19		–		19
Total other income and deductions		(92	)	–		(92	)
Income (loss) before income taxes		(54	)	148		94
Income taxes		(23	)	60	(b),(c)	37
Net Income (loss)		(31	)	88		57
Preferred security dividends		11		–		11
Net income (loss) on common stock		(42	)	88		46

Note: Financial results for BGE beginning on March 12, 2012, the date the merger was completed.

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses

(e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(c) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

        20

Exelon Generation – Annual Electric Supply and Sales Statistics

Twelve Months Ended December 31,
(in GWhs)	2012	(a)	2011
Supply
Nuclear Generation(b)
Mid-Atlantic	47,337		47,287
Midwest	92,525		92,010
Total Nuclear Generation	139,862		139,297
Fossil and Renewables(b)
Mid-Atlantic(b)(d)	8,808		7,572
Midwest	971		596
New England	9,965		8
New York	–		–
ERCOT(e)	6,182		2,030
Other(f)	5,913		1,432
Total Fossil and Renewables	31,839	��	11,638
Purchased Power
Mid-Atlantic(c)	20,830		2,898
Midwest	9,805		5,970
New England	9,273		–
New York(c)	11,457		–
ERCOT(e)	23,302		7,537
Other(f)	17,327		2,503
Total Purchased Power	91,994		18,908
Total Supply/Sales by Region(h)
Mid-Atlantic(g)	76,975		57,757
Midwest(g)	103,301		98,576
New England	19,238		8
New York	11,457		–
ERCOT	29,484		9,567
Other(f)	23,240		3,935
Total Supply/Sales by Region	263,695		169,843
Average Margin ($/MWh)(i)(j)
Mid-Atlantic(k)	$44.60		$58.00
Midwest(k)	29.02		35.99
New England	10.19		n.m.
New York	6.63		n.m.
ERCOT	13.74		8.78
Other(f)	5.64		(3.56	)
	–		–
Average Margin – Overall Portfolio	$27.45		$41.07
Around-the-clock (ATC) Market Prices ($/MWh)(l)
PJM West Hub	$33.91		$43.56
NiHub	28.97		33.07
NEPOOL Mass Hub	6.06		8.71
NYPP Zone A	31.02		36.98
ERCOT North Spark Spread	3.23		11.88

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 9,925 GWhs in the Mid-Atlantic and 9,350 GWhs in New York as a result of the PPA with CENG for the year ended December 31, 2012.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 12,958 GWhs and 5,742 GWhs for the year ended December 31, 2012 and 2011, respectively.

(i) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

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

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the year.

21        

Exelon Generation – Electric Supply and Sales by Quarter

	Three Months Ended
(in GWhs)		December 31, 2012	(a)		September 30, 2012	(a)			June 30, 2012	(a)		March 31, 2012		December 31, 2011
Supply
Nuclear Generation(b)
Mid-Atlantic		11,547			11,449				12,277			12,064		11,587
Midwest		23,335			23,132				22,860			23,198		23,306
Total Nuclear Generation		34,882			34,581				35,137			35,262		34,893
Fossil and Renewables(b)
Mid-Atlantic(b)(d)		2,154			2,547				2,316			1,791		1,637
Midwest		300			171				228			272		188
New England		2,368			3,953				2,755			889		–
New York		–			–				–			–		–
ERCOT(e)		755			2,410				2,177			840		457
Other(f)		1,358			1,813				1,923			819		394
Total Fossil and Renewables		6,935			10,894				9,399			4,611		2,676
Purchased Power
Mid-Atlantic(c)		4,332			6,811				7,111			2,577		739
Midwest		2,661			3,035				1,558			2,552		1,143
New England		2,304			1,961				3,905			1,100		–
New York(c)		3,678			4,026				2,818			935		–
ERCOT(e)		6,043			7,741				6,686			2,832		1,150
Other(f)		4,172			5,372				6,012			1,769		482
Total Purchased Power		23,190			28,946				28,090			11,765		3,514
Total Supply/Sales by Region(h)
Mid-Atlantic(g)		18,033			20,807				21,704			16,432		13,963
Midwest(g)		26,296			26,338				24,646			26,022		24,637
New England		4,672			5,914				6,660			1,989		–
New York		3,678			4,026				2,818			935		–
ERCOT		6,798			10,151				8,863			3,672		1,607
Other(f)		5,530			7,185		��		7,935			2,588		876
Total Supply/Sales by Region		65,007			74,421				72,626			51,638		41,083
	Three Months Ended
	December 31, 2012(a)			September 30, 2012(a)				June 30, 2012(a)			March 31, 2012		December 31, 2011
Average Margin ($/MWh)(f)(g)(h)
Mid-Atlantic(k)		$48.24			$43.64				$40.68			$46.86		$56.08
Midwest(k)		26.09			27.68				31.00			31.40		34.18
New England		3.64			13.70				9.01			19.61		n.m.
New York		4.35			3.23				13.84			8.56		n.m.
ERCOT		13.39			15.66				13.43			9.26		(6.02	)
Other(f)		7.96			5.85				4.28			5.41		(4.13	)
Average Margin – Overall Portfolio		$26.52			$25.96				$26.15			$32.57		$39.31
Around-the-clock Market Prices ($/MWh)(l)
PJM West Hub		$35.94			$38.13				$30.40			$31.10		$35.07
NiHub		28.37			34.29				26.02			27.13		25.97
New England Mass Hub ATC Spark Spread		3.07			12.69				7.77			0.80		6.71
NYPP Zone A		34.70			34.56				27.87			27.18		32.03
ERCOT North Spark Spread		(0.27	)		3.60				6.01			3.46		1.11

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 3,255 GWhs, 3,126 GWhs, 3,225 GWhs and 319 GWhs in the Mid-Atlantic and 2,814 GWhs, 2,997 GWhs, 2,817 GWhs and 722 GWhs in New York as a result of the PPA with CENG for the three months ended December 31, 2012, September 30, 2012, June 30, 2012 and March 31, 2012, respectively.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2102 as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 2,977 GWhs, 4,352 GWhs, 3,873 GWhs, 1,757 GWhs, and 1,235 GWhs for the three months ended December 31, 2012, September 30, 2012, June 30, 2012, March 31, 2012, and December 31, 2011, respectively.

(i) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

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

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the year.

        22

ComEd – Electric Sales Statistics, Revenue and Customer Detail

	2012		2011
Retail Deliveries(a)(in GWhs)
Residential		28,528		28,273
Small Commercial & Industrial		32,534		32,281
Large Commercial & Industrial		27,643		27,732
Public Authorities & Electric Railroads		1,272		1,235
Total Retail Deliveries		89,977		89,521
Electric Revenue (in millions)
Residential		$3,037		$3,510
Small Commercial & Industrial		1,339		1,517
Large Commercial & Industrial		395		383
Public Authorities & Electric Railroads		44		50
Total Retail Revenues		4,815		5,460
Other Revenues(b)		628		596
Total Electric Revenues		$5,443		$6,056
Customers at Year End
	2012		2011
Number of Electric Customers
Residential		3,455,546		3,448,481
Small Commercial & Industrial		365,357		365,824
Large Commercial & Industrial		1,980		2,032
Public Authorities & Electric Railroads		4,812		4,797
Total Electric Customers		3,827,695		3,821,134
Heating and Cooling Degree Days
	2012		2011
Heating Degree Days(normal=6,341)		5,065		6,134
Cooling Degree Days(normal=842)		1,324		1,036
Peak System Load
	2012		2011
Summer(c)
Highest Peak Load (MW)		23,601		23,753	(d)
Winter(e)
Highest Peak Load (MW)		14,812		15,656

(a) Reflects delivery volumes and revenues 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 and transmission.

(b) Other revenue primarily includes transmission revenue from PJM. Other items include late payment charges and mutual assistance program revenues.

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

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

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

23        

PECO – Electric Sales Statistics, Revenue and Customer Detail

	2012		2011
Retail Deliveries(a)(in GWhs)
Residential		13,233		13,687
Small Commercial & Industrial		8,063		8,321
Large Commercial & Industrial		15,253		15,677
Public Authorities & Electric Railroads		943		945
Total Retail Deliveries		37,492		38,630
Electric Revenue (in millions)
Residential		1,689		$1,934
Small Commercial & Industrial		462		584
Large Commercial & Industrial		232		308
Public Authorities & Electric Railroads		31		38
Total Retail Revenues		2,414		2,865
Other Revenues(b)		226		244
Total Electric Revenues		2,640		$3,109
Customers at Year End
	2012		2011
Number of Electric Customers
Residential		1,417,773		1,415,681
Small Commercial & Industrial		148,803		148,570
Large Commercial & Industrial		3,111		3,110
Public Authorities & Electric Railroads		9,660		9,689
Total Electric Customers		1,579,347		1,577,050
Heating and Cooling Degree Days
	2012		2011
Heating Degree Days(normal=4,603)		3,747		4,157
Cooling Degree Days(normal=1,301)		1,603		1,617
Peak System Load
	2012		2011
Summer(c)
Highest Peak Load (MW)		8,549		8,983	(d)
Winter(e)
Highest Peak Load (MW)		6,652		6,675

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

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

        24

PECO – Gas Sales Statistics, Revenue and Customer Detail

	2012		2011
Deliveries to Customers (in mmcf)
Retail Sales(a)		49,767		54,239
Transportation and Other		26,687		28,204
Total Gas Deliveries		76,454		82,443
Gas Revenue (in millions)
Retail Sales(a)		509		$576
Transportation and Other		37		35
Total Gas Revenue		546		$611
Gas Customers at Year End
	2012		2011
Residential		454,502		451,382
Commercial & Industrial		41,836		41,373
Total Retail Customers		496,338		492,755
Transportation		903		879
Total Gas Customers		497,241		493,634
Gas Maximum Day Sendout
	2012		2011
Winter
Maximum Day Sendout (in thousand cubic feet (mcf))		702,895		667,061

(a) Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

25        

Owned net electric generating capacity by station at December 31, 2012:

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 (MW	(b)  )
Nuclear
Braidwood	Braidwood, IL	2	100		Uranium	Base-load	2,349
Byron	Byron, IL	2	100		Uranium	Base-load	2,326
Calvert Cliffs(d)	Lusby, MD	2	50.01		Uranium	Base-load	877
Clinton	Clinton, IL	1	100		Uranium	Base-load	1,067
Dresden	Morris, IL	2	100		Uranium	Base-load	1,790
LaSalle	Seneca, IL	2	100		Uranium	Base-load	2,327
Limerick	Limerick Twp., PA	2	100		Uranium	Base-load	2,314
Nine Mile Point(d)	Scriba, NY	2	44.2		Uranium	Base-load	798
Oyster Creek	Forked River, NJ	1	100		Uranium	Base-load	625	(c)
Peach Bottom	Peach Bottom Twp., PA	2	50.00		Uranium	Base-load	1,158	(d)
Quad Cities	Cordova, IL	2	75.00		Uranium	Base-load	1,403	(d)
R.E. Ginna(d)	Ontario, NY	1	50.01		Uranium	Base-load	288
Salem	Hancock’s Bridge, NJ	2	42.6		Uranium	Base-load	1,006	(d)
Three Mile Island	Londonderry Twp, PA	1	100		Uranium	Base-load	837
							19,165
Fossil (Combined Cycle Gas Turbines)
Colorado Bend	Wharton, TX	6			Gas	Intermediate	498
Fore River	North Weymouth, MA	3			Gas	Intermediate	688
Hillabee	Alexander City, AL	3			Gas	Intermediate	684
Mystic 8/9	Charlestown, MA	6			Gas	Intermediate	1,382
Quail Run	Odessa, TX	6			Gas	Intermediate	488
Wolf Hollow	Granbury, TX	3			Gas	Intermediate	705
							4,445

        26

Owned net electric generating capacity by station at December 31, 2012:

								Net
						Primary		Generation
		Number	Percent		Primary		Dispatch		Capacity	(b)
Station	Location	of Units	Owned	(a)	Fuel Type		Type		(MW	)
Fossil (Combustion Turbines)
Chester	Chester, PA	3			Oil		Peaking		39
Croydon	Bristol Twp., PA	8			Oil		Peaking		391
Delaware	Philadelphia, PA	4			Oil		Peaking		56
Eddystone	Eddystone, PA	4			Oil		Peaking		60
Falls	Falls Twp., PA	3			Oil		Peaking		51
Framingham	Framingham, MA	3			Oil		Peaking		28
Grande Prairie	Alberta, Canada	1			Gas		Peaking		93
Handsome Lake	Rockland Twp., PA	5			Gas		Peaking		268
LaPorte	Laporte, TX	4			Gas		Peaking		152
Medway	West Medway, MA	3			Oil/Gas		Peaking		105
Moser	Lower Pottsgrove Twp., PA	3			Oil		Peaking		51
Mystic Jet	Charlestown, MA	1			Oil		Peaking		9
New Boston GT	South Boston, MA	1			Oil		Peaking		12
Notch Cliff	Baltimore Co., MD	8			Gas		Peaking		101
Perryman	Harford Co., MD	5			Oil/Gas		Peaking		347
Philadelphia Road	Baltimore Co., MD	4			Oil		Peaking		61
Richmond	Philadelphia, PA	2			Oil		Peaking		98
Riverside 6-8	Baltimore Co., MD	3			Oil/Gas		Peaking		154
Salem	Hancock’s Bridge, NJ	1	42.59		Oil		Peaking		16	(d)
Schuylkill 10-11	Philadelphia, PA	2			Oil		Peaking		30
Southeast Chicago	Chicago, IL	8			Gas		Peaking		296
Southwark	Philadelphia, PA	4			Oil		Peaking		52
West Valley	Salt Lake City, UT	5			Gas		Peaking		200
Westport-5	Baltimore Co., MD	1			Gas		Peaking		116
									2,786
								Net
						Primary		Generation
		Number	Percent		Primary		Dispatch		Capacity	(b)
Station	Location	of Units	Owned	(a)	Fuel Type		Type		(MW	)
Hydroelectric and Renewable
AgriWind	Bureau Co., IL	4	99		Wind		Base-load		8	(d)
Antelope Valley Solar Ranch	LA County, CA	n/a			Solar		Base-load		31
Beebe	Gratiot, MI	34			Wind		Base-load		81
Blue Breezes/Moore	MN	2			Wind		Base-load		3
Bluegrass Ridge	Gentry Co., MO	27	99		Wind		Base-load		57	(d)
Brewster	Jackson Co., MN	6	97		Wind		Base-load		6	(d)
Cassia	Twin Falls Co., ID	14			Wind		Base-load		29
Cisco	Jackson Co., MN	4	99		Wind		Base-load		8	(d)
Conception	Nodaway Co., MO	24			Wind		Base-load		50
Conowingo	Harford Co., MD	11			Hydroelectric		Base-load		572
Constellation Solar(e)	Various	-			Solar		Base-load		115
Cow Branch	Atchinson Co., MO	24			Wind		Base-load		50
Cowell	Pipestone Co., MN	1	99		Wind		Base-load		2	(d)
CP Windfarm	Faribault Co., MN	2			Wind		Base-load		4
Criterion	Oakland, MD	28			Wind		Base-load		70
Echo I	Umatilla Co., OR	21	99		Wind		Base-load		35	(d)
Echo II	Morrow Co., OR	10			Wind		Base-load		20
Echo III-Landowner	Morrow Co., OR	6	99		Wind		Base-load		10	(d)
Ewington	Jackson Co., MN	10	99		Wind		Base-load		21	(d)
Exelon Solar Chicago	Cook Co., IL	n/a			Solar		Base-load		10

27        

Owned net electric generating capacity by station at December 31, 2012: (continued)

								Net
						Primary		Generation
		Number	Percent		Primary		Dispatch		Capacity	(b)
Station	Location	of Units	Owned	(a)	Fuel Type		Type		(MW	)
Hydroelectric and Renewable
Exelon Wind 1	Hansford Co., TX	8			Wind		Base-load		10
Exelon Wind 2	Hansford Co., TX	8			Wind		Base-load		10
Exelon Wind 3	Hansford Co., TX	8			Wind		Base-load		10
Exelon Wind 4	Hansford Co., TX	38			Wind		Base-load		80
Exelon Wind 5	Sherman Co., TX	8			Wind		Base-load		10
Exelon Wind 6	Sherman Co., TX	8			Wind		Base-load		10
Exelon Wind 7	Moore Co., TX	8			Wind		Base-load		10
Exelon Wind 8	Moore Co., TX	8			Wind		Base-load		10
Exelon Wind 9	Moore Co., TX	8			Wind		Base-load		10
Exelon Wind 10	Moore Co., TX	8			Wind		Base-load		10
Exelon Wind 11	Moore Co., TX	8			Wind		Base-load		10
Fairless	Falls Twp, PA	2			Landfill Gas		Base-load		60
Greensburg	Kiowa Co, KS	10			Wind		Base-load		13
Harvest I	Huron Co., MI	32			Wind		Base-load		53
Harvest II	Huron Co., MI	33			Wind		Base-load		59
High Plains	Moore Co., TX	8	99.5		Wind		Base-load		10	(d)
HighMesa	Twin Fall Co, ID	19			Wind		Base-load		40
Loess Hills	Atchinson Co., MO	4			Wind		Base-load		5
Malacha	Muck Valley, CA	1	50.0		Hydro		Base-load		16	(d)
Marshall	Lyon Co., MN	9	99.0		Wind		Base-load		19	(d)
Michigan Wind I	Bingham township, MI	46			Wind		Base-load		69
Michigan Wind II	Minden City, MI	50			Wind		Base-load		90
Mountain Home	Elsmore Co., ID	20			Wind		Base-load		42
Muddy Run	Lancaster Co., PA	8			Hydro		Intermediate		1,070
Norgaard	Lincoln Co., MN	7	99.0		Wind		Base-load		9	(d)
Pennsbury	Falls Twp., PA	2			Landfill Gas		Peaking		6
Safe Harbor	Safe Harbor, PA	12	66.7		Hydro		Base-load		277	(d)
SEGS IV (12.2%)	Kramer Junction, CA	n.a.	12.2		Solar		Base-load		4	(d)
SEGS V (4.2%)	Kramer Junction, CA	n.a.	4.2		Solar		Base-load		1	(d)
SEGS VI (8.8%)	Kramer Junction, CA	n.a.	8.8		Solar		Base-load		3	(d)
Shooting Star	Kiowa Co, KS	65			Wind		Base-load		104
Threemile Canyon	Morrow Co., OR	6			Wind		Base-load		10
Tuana Springs	Twin Fall Co, ID	8			Wind		Base-load		17
Whitetail	Webb, TX	57			Wind		Base-load		92
Wildcat	Lea, NM	13			Wind		Base-load		27
Wolf	Nobles Co.,MN	5	99.0		Wind		Base-load		6	(d)
									3,464

        28

Owned net electric generating capacity by station at December 31, 2012:

								Net
						Primary		Generation
		Number	Percent		Primary		Dispatch		Capacity	(b)
Station	Location	of Units	Owned	(a)	Fuel Type		Type		(MW	)
Fossil (Internal Combustion/Diesel)
Conemaugh	New Florence, PA	4	31.3%		Oil		Peaking		3	(d)
Keystone	Shelocta, PA	4	42.0%		Oil		Peaking		4	(d)
									7
Fossil (Steam Turbines)(e)
Colver	Colver Township, PA	1	25.0		Waste Coal		Base Load		26	(d)
Conemaugh	New Florence, PA	2	31.3		Coal		Base Load		531	(d)
Eddy 3, 4	Eddystone, PA	2			Oil/Gas		Intermediate		760
Gould Street	Baltimore, MD	1			Gas		Peaking		97
Handley 3	Fort Worth, TX	1			Gas		Intermediate		395
Handley 4, 5	Fort Worth, TX	2			Gas		Peaking		870
Keystone	Shelocta, PA	2	42.0		Coal		Base Load		714	(d)
Mountain Creek 6, 7	Dallas, TX	2			Gas		Peaking		240
Mountain Creek 8	Dallas, TX	1			Gas		Intermediate		565
Mystic 7	Charlestown, MA	1			Oil/Gas		Peaking		560
Riverside 4	Baltimore Co., MD	1			Gas		Peaking		74
Sunnyside	Sunnyside, UT	1	50.0		Waste Coal		Base Load		26	(d)
Wyman 4	Yarmouth	1	5.9%		Oil		Intermediate		36	(d)
									4,895
Total Owned Generation (in MW)									34,761

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

(a) Ownership is 100% unless otherwise noted.

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

(c) On December 8, 2010, Exelon 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) Constellation Solar is an operation that constructs, owns and operates solar facilities at various customer locations.

29        

Exelon Nuclear Fleet^(a)(b)

(At December 31, 2012)

	Location			Owned Net		2012		Plant		NSSS
Station	Water Body	Ownership		Capacity (MW)		Generation (GWh)		Type		Vendor
Braidwood	Braidwood, IL		100% Exelon		2,349		18,806		PWR		W
2 units	Kankakee River
Byron	Byron, IL		100% Exelon		2,326		18,318		PWR		W
2 units	Rock River
Calvert Cliffs	Lusby, MD		50.01% Exelon		877		6,783		PWR		CE
2 units	Chesapeake Bay		49.99% EDF
Clinton	Clinton, IL		100% Exelon		1,067		9,375		BWR		GE
1 unit	Clinton Lake
Dresden	Morris, IL		100% Exelon		1,790		14,802		BWR		GE
2 units	Kankakee River
LaSalle	Seneca, IL		100% Exelon		2,327		19,595		BWR		GE
2 units	Illinois River
Limerick	Limerick Township, PA		100% Exelon		2,314		18,156		BWR		GE
2 units	Schuylkill River(g)
Nine Mile Point	Scriba, NY		44.20% Exelon(h)		798		5,864		BWR		GE
2 units	Lake Erie		44.19% EDF(h)
			11.61% LIPA(h)
Oyster Creek	Forked River, NJ		100% Exelon		625		4,715		BWR		GE
1 unit	Barnegat Bay
Peach Bottom	Peach Bottom, PA		50% Exelon		1,158		9,403		BWR		GE
2 units	Susquehanna River		50% PSEG Nuclear
Quad Cities	Cordova, IL		75% Exelon		1,403		11,629		BWR		GE
2 units	Mississippi River		25% Mid-American
			Energy Holdings
R.E. Ginna	Ontario, NY		50.01% Exelon		288		2,301		PWR		W
1 unit	Lake Erie		49.99% EDF
Salem	Hancock’s Bridge, NJ		42.6% Exelon		1,006		8,026		PWR		W
2 units	Deleware Estuary		57.4% PSEG Nuclear
Three Mile	Londonderry		100% Exelon		837		7,038		PWR		B&W
Island	Township, PA
1 unit	Susquehanna River
Total					19,165		154,812

Notes: Average in-service time = 31 years

PWR = Pressurized Water Reactor; BWR = Boiling Water Reactor

NSSS = Nuclear Steam Supply System; W = Westinghouse; CE = Combustion Engineering; GE = General Electric;

B&W = Babcock & Wilcox Amounts may not add due to rounding

(a) Fleet also includes 4 units that have been shut down: Peach Bottom 1, Dresden 1, Zion 1 and 2

(b) Total owned Capacity, net annual mean unit ratings, and 2011 Generation are stated at ownership portion.

(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) 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)

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

Nuclear Operating Data^(a)

	2012		2011		2010
Fleet capacity factor		92.7%		93.3%		93.9%
Fleet production cost per MWh		$19.50		$18.86		$17.31

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

Refueling Outages in 2012

– Conducted 10 refueling outages – including Salem

– Average refueling outage duration – excluding Salem: 30 days

        30

	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	%	1,192	1988	2026		May-12(d)	Dry Cask Storage
(dedicated ponds)			2/100	%	1,157	1988	2027		Nov-12(d)	in operation
Byron	Closed		1/100	%	1,172	1985	2024		Oct-12(d)	Dry Cask Storage
			2/100	%	1,154	1987	2026		Oct-11(d)	in operation
Calvert Cliffs	Open		1/50.01	%	445	1975	2034		Apr-12(e)	ISFSI in operation
			2/50.01	%	432	1977	2036		Mar-11(e)
Clinton	Open		1/100	%	1,067	1987	2026		Dec-11(e)	2015
Dresden	Partial Open		2/100	%	917	1970	2029		Nov-11(e)	Dry Cask Storage
			3/100	%	873	1971	2031		Dec-12(e)	in operation
LaSalle	Closed		1/100	%	1,157	1984	2022		Mar-12(e)	Dry Cask Storage
			2/100	%	1,170	1984	2023		Mar-13(e)	in operation
Limerick	Closed		1/100	%	1,157	1986	2024		Mar-12(e)	Dry Cask Storage
			2/100	%	1,157	1990	2029		Apr-11(e)	in operation
Nine Mile Point	Open/		1/50.01	%	307	1970	2029		Apr-11(e)	Fuel pool not full;
	Closed		2/41.01	%	491	1988	2046		Jun-12(e)	ISFSI under
										construction
Oyster Creek	Open		1/100	%	625	1969	2029	(i)	Dec-12(e)	Dry Cask Storage
										in operation
Peach Bottom	Open		2/50	%	574	1974	2033		Oct-12(e)	Dry Cask Storage
			3/50	%	584	1974	2034		Oct-11(e)	in operation
Quad Cities	Open	��	1/75	%	700	1973	2032		Jun-11(e)	Dry Cask Storage
			2/75	%	703	1973	2032		Apr-12(e)	in operation
R.E. Ginna	Open		1/50.01	%	288	1970	2029		Nov-12(d)	ISFSI in operation
Salem	Open		1/43	%	504	1977	2036		Nov-11(d)	Dry Cask Storage
			2/43	%	502	1981	2040		Nov-12(d)	in operation
Three Mile	Closed		1/100	%	837	1974	2034		Nov-11(e)	2023
Island

Nuclear Operating Data^(a) (continued)

2012 Net Generation (excluding Salem): 131,838 MWh

Planned Refueling Outages (including Salem)

2010:     10 actual                 2013: 10 planned

2011:     12 actual                 2014: 11 planned

2012:     10 actual                 2015: 11 planned

CENG Nuclear Operating data
	2012		2011		2010
Fleet capacity factor		86.7%		92.0%		93.4%
Fleet production cost per MWh		$31.10		$25.35		$21.33
Refueling Outages in 2012
– Conducted 3 refueling outages

Planned Refueling Outages

2011:     3 actual                2014: 3 planned

2012:     3 actual                2015: 3 planned

2013:     2 planned             2016: 2 planned

31        

Owned generation as of December 31, 2012, unless otherwise noted. Table does not include station auxiliary equipment or plants comprised solely of peaking combustion turbines. 2012 data is presented for the full calendar year.

			Net Generation Available for Sale (GWh)
Fossil Station (Location) / Water Body	Capacity (MW)	(a)		2012	2011	2010
Brandon Shores(c) (Baltimore, MD) / Patapsco River	1,273			4,605	5,868	6,032
Units: 2 coal units (baseload) – Divested
Conemaugh (New Florence, PA) / Conemaugh River	531			3,324	3,382	3,803
Units: 2 coal units (baseload)
Data reflects Exelon Generation’s 31.28% plant ownership.
Colorado Bend Energy Center (Wharton, TX) / Colorado River	498			1,644	1,524	819
Units: 4 2x1 CCGTs & 2 steam generators (intermediate)
C.P. Crane(c) (Baltimore, MD) / Seneca Creek	399			597	970	845
Units: 2 coal units (intermediate) & 1 oil combustion turbine (peaking)
Eddystone(b) (Eddystone, PA) / Delaware River	820			46	427	2,033
Units: 2 coal units (intermediate) – Retired,
2 oil/gas steam units (intermediate), 4 combustion turbines (peaking)
Fairless Hills (Falls Township, PA) / Delaware River(d)	60			247	242	239
Units: 2 landfill gas units (peaking)
Fore River (North Weymouth, MA) / Town River	688			4,048	4,781
Units: 4 2x1 CCGTs & 3 steam generators (intermediate)
Gould Street (Baltimore MD) / Patapsco River	97			40	21	22
Units: 1 gas steam unit (peaking)
Handley (Ft. Worth, TX) / Lake Arlington	1,265			858	585	362
Units: 3 gas steam units (2 peaking/1 intermediate)
H.A. Wagner(c) (Baltimore, MD) / Patapsco River	976			1,097	1,538	1,644
Units: 1 oil/gas steam unit, 2 coal units, 1 oil steam unit,
& 1 oil combustion turbine (intermediate) – Divested

        32

Emissions (thousand tons)							Reduction Technology
										Post			Low NOx
										combustion			burners with			Induced	Cooling
							SO2			NOx controls			separated			flue gas	Water
Type	2012		2011		2010		Scrubber			(SCR or SNCR)			overfire air			recirculation	System
Brandon Shores
SO2		2.8		2.8		1.3		X
NOx		4.0		4.8		3.8					X			X
CO2		5,204		6,610		6,330												Closed
Conemaugh
SO2		2.0		2.3		2.2		X
NOx		5.1		5.5		6.0					2015			X
CO2		3,368		3,349		3,756												Closed
Colorado Bend
SO2		*		*		*
NOx		0.1		0.1		0.1
CO2		830		759		513												Closed
C.P. Crane
SO2		1.7		5.7		5.6
NOx		1.6		2.5		2.5					X
CO2		815		1,242		1,050												Open
Eddystone
SO2		0.1		0.9		4.9		X
NOx		0.1		0.8		3.8		(Coal Units	)		X			X
CO2		99		577		2,750					(Coal Units	)		(Coal Units	)			Open
Fairless Hills
SO2		0.1		0.1		0.1
NOx		0.1		0.1		0.1
CO2		353		208		201												Open
Fore River
SO2		*		*
NOx		0.1		0.1							X
CO2		1,733		2,018														Closed
Gould Street
SO2		*		*		*
NOx		*		*		*								X
CO2		29		17		18												Open
Handley
SO2		*		*		*
NOx		0.1		0.1		*					X
CO2		601		422		264												Open
H.A Wagner
SO2		7.5		9.1		9.2
NOx		1.6		1.7		1.5					X			X
CO2		1,361		1,760		1,820												Open

33        

Owned generation as of December 31, 2012, unless otherwise noted. Table does not include station auxiliary equipment or plants comprised solely of peaking combustion turbines. 2012 data is presented for the full calendar year.

				Net Generation Available for Sale (GWh)
		Capacity	(a)
Fossil Station (Location) / Water Body	(MW)			2012		2011		2010
Hillabee Energy Center (Alexander City, AL) / Municipal Supply		684			5,007		4,166		2,389
Units: 2 2x1 CCGTs & 1 steam generator (intermediate)
Keystone (Shelocta, PA) / Keystone Lake(f)		714			3,998		4,697		5,688
Units: 2 coal units (baseload)
Data reflects Exelon Generation’s 41.98% plant ownership.
Mountain Creek (Dallas, TX) / Mountain Creek cooling pond		717			847		627		726
Units: 3 gas steam units (2 peaking/1 intermediate)
Mystic & Mystic Jet (Charlestown, MA) / Mystic River		1,951			8,627		9,324
Units: 4 2x1 CCGT, 3 steam generators
& 1 combustion turbine (intermediate)
Quail Run Energy Center (Odessa, TX) / Municipal		488			416		681		736
Units: 4 2x1 CCGT & 2 steam generators (intermediate)
Riverside (Baltimore, MD) / Patapsco River		228			27		20		13
Units: 1 gas steam unit & 3 gas/oil combustion turbines (peaking)
Schuylkill (Philadelphia, PA) / Schuylkill River		196			<1		6		8
Units: 1 oil steam unit (peaking), 2 combustion turbines (peaking)
Wolf Hollow(e) (Granbury, TX) / Lake Granbury		705			2,604		654
Units: 2 gas combined cycle turbines and 1 steam generator (intermediate)

(a) Capacity reflects summer rating and is reported at ownership portion. Divested plant capacity is as of 12/31/11. Capacity presented does not reflect retired unit capacity.

(b) Eddystone Unit 1 (coal) was retired on May 31, 2011; Eddystone Unit 2 (coal) was retired on May 31, 2012. Retired unit capacity is not included in plant totals.

(c) Constellation’s Maryland coal plants were divested in 2012 according to the terms of the merger agreement with the state of Maryland. 2012 data for divested coal plants is estimated for period of ownership in 2012.

(d) Fairless Hills CO2 emissions include biogenic CO2 from landfill gas; biogenic CO2 accounted for 98% of CO2 emissions in 2012.

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

(f) 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.

        34

Emissions (thousand tons)

Reduction Technology

Post

Low NOx

combustion

burners with

Induced

Cooling

SO2

NOx controls

separated

flue gas

Water

Type

2012

2011

2010

Scrubber

(SCR or SNCR)

overfire air

recirculation

System

Hillabee

Energy Ctr.

SO2

*

*

*

NOx

0.2

0.1

0.1

X

CO2

2,123

1,786

1,020

Closed

Keystone

SO2

12.4

19.5

16.4

X

NOx

7.3

8.7

2.3

X

X

CO2

4,121

4,766

5,607

Closed

Mountain

Creek

SO2

*

*

*

NOx

0.2

0.1

0.1

X

X

CO2

571

457

489

(Unit 8

)

(Units 6, 7

)

Open

Mystic &

Mystic Jet

SO2

*

*

NOx

0.3

0.3

X

X

CO2

3,735

4,102

Closed

Quail Run

Energy Cnt.

SO2

*

*

*

NOx

0.1

0.1

0.1

X

X

CO2

245

398

360

Closed

Riverside

SO2

*

*

*

NOx

*

*

*

CO2

21

20

13

Open

Schuylkill

SO2

*

*

*

NOx

*

*

*

CO2

1

15

16

Open

Wolf

Hollow

SO2

*

*

NOx

0.4

0.1

X

CO2

1,231

330

Closed

*Indicates emissions less than 50 tons.

35        

Contracted Generation (in MWs) as of December 31, 2012

	2013		2014		2015
ERCOT
Oil/Gas		885		885		830
Renewables		203		203		203
Total		1,088		1,088		1,033
Mid-Atlantic(a)
Oil/Gas		695		695		695
Renewables		278		221		221
Total		973		916		916
Midwest
Coal		1,158		–		–
Oil/Gas		1,157		1,157		1,157
Renewables		666		612		612
Total		2,981		1,769		1,769
NEPOOL
Oil/Gas		620		620		620
Renewables		17		17		17
Total		637		637		637
New York(a)
Nuclear		100		–		–
Total		100		–		–
South/West/Canada
Oil/Gas		3,184		3,184		3,184
Renewables		332		332		332
Total		3,516		3,516		3,516
Total Contracted Generation		9,296		7,926		7,871

(a) Excludes PPA with CENG

Exelon Corporation

10 South Dearborn Street, 52nd Floor

Chicago, IL 60603

www.exeloncorp.com

© Exelon Corporation, 2013

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