Exhibit 99.1
Exelon Corporation
2013 Fact Book
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 2013 Generation Fuel Mix Exelon 4
Credit and Liquidity for Exelon and Operating Companies Credit Ratings, Credit Facilities and Commercial Paper 5
Long Term Debt Outstanding as of December 31, 2013 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, 17 Exelon Generation 18 ComEd 19 PECO 20 BGE 21
Supply and Sales Statistics Exelon Generation 22-24 ComEd 25 PECO 26, 27 BGE 28, 29
Exelon Generation – Generating Resources Total Owned Generating Capacity 30-33 Exelon Nuclear Fleet and Nuclear Operating Data 34, 35 Fossil Emissions and Emission Reduction Technology Summary 36-39 Exelon Generation – Total Contracted Generation Capacity 40
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 email inquiries, visit the Investor section 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 StreetChicago, IL 60603 Twitter312.394.2345 @Exelon
Cautionary Statements Regarding Forward-Looking Information
This presentation 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 2013 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 22; and (2) 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 presentation (June 30, 2014). 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 presentation.
2
Exelon at a Glance
Company Profile
Headquartered in Chicago, Exelon is the nation’s leading competitive energy provider, doing business in 48 states, the District of Columbia and Canada. The company is one of the largest competitive U.S. power generators, with more than 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 7.8 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).
Our Mission
Exelon’s mission is to be the leading diversified energy company — by providing reliable, clean, affordable and innovative energy products.
Our Vision
Performance that drives progress. At Exelon, we believe that reliable, clean and affordable energy is essential to a brighter, more sustainable future. That’s why we’re committed to providing innovation, best-in-class performance and thought leadership to help drive progress for our customers and the communities we serve.
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 2013
$24.9billion in operating revenues
$79.9billion in assets
6.6million electric customers
1.2million gas customers
~26,000employees
7,407circuit miles of electric transmission lines
~35,000MW U.S. generating capacity
~150terawatt-hours of electric load served
410 billion cubic feet of natural gas served
$1.24 annual dividend rate per share(a)
(a) During 2013, 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 was based on our previous level of $2.10 per share on an annualized basis, while the new dividend declares a $0.31 per share quarterly dividend which began in the second quarter of 2013 (or $1.24 per share on an annualized basis). Exelon intends to maintain the normal cadence of quarterly dividends, which are subject to declaration by the Board of Directors.
3
Company Overview
Exelon Family of Companies
CompetitiveEnergy Sales
Transmission & Delivery
Generation
Exelon Generation is one of the largestcompetitive 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.
Constellation, 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 Canada. Constellation’s retail businesses serve approximately 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 more than 7.8 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 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 501,000 natural gas customers.
Exelon Service Area and Generation Fuel Mix
Exelon Service Area and Selected Generation Assets as of December 31, 2013Exelon AssetsNuclearGas/Oil intermediatePeakersCoalRenewable (Hydro, Wind, Solar, Biomass)Competitive Retail and/orGas or Electric Wholesale OperationsWestMISOBGEComEdPECOISO-NE & NYPJMSERCERCOTRegional TransmissionOrganization (RTO)ServiceAreasHeadquarters Locations
2013 Generation Fuel Mix Exelon – Ownership Equity
Fuel by Capacity (MW)
Nuclear 55%
Gas 28%
Hydro & Renewables 10%
Coal 4%
Oil 3%
4
Credit and Liquidity for Exelon and Operating Companies
Credit Ratings as of February 28, 2014
Moody’s Investors Standard & Poor’s Service Corporation Fitch Ratings
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 A3 A- BBB+
Commercial Paper P2 A2 F2
ComEd
Senior Secured Debt A2 A- A-
Senior Unsecured Debt Baa1 BBB BBB+
Commercial Paper P2 A2 F2
PECO
Senior Secured Debt Aa3 A- A
Senior Unsecured Debt A2 N/A A-
Commercial Paper P1 A2 F2
Indicative Rating
Negative Outlook
Credit Facilities and Commercial Paper as of February 28, 2014
Exelon
BGE ComEd PECO Generation 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) (1,658) (2) (1,661)
Available Capacity under Facilities(b) 600 1,000 599 4,017 498 6,714
Outstanding Commercial Paper – (435) – – – (435)
Available Capacity less Outstanding Comm. Paper $600 $565 $599 $4,017 $498 $6,279
(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
6 Long-Term Debt Outstanding as of December 31, 2013
Exelon Corporation Interest Date Maturity Total Debt Current Long-TermSeries Rate Issued Date Outstanding Portion 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
Maturities 2014 2015 2016 2017 2018
– $800 – – –
Exelon Generation Interest Date Maturity Total Debt Current Long-TermSeries Rate Issued Date Outstanding Portion 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 – 5502012 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 – 3502012 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 – 550CEG 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 Exelon Wind 2.00% 12/10/10 7/31/17 1 – 1
Total Senior Notes $6,270 $500 $5,770
Non Regulated Business Pollution Control Loan(b) 4.10% 12/20/84 7/1/14 $20 $20 $–CEU Credit Agreement 2.21% 7/22/11 7/22/16 77 – 77Clean Horizons Solar Term Loan Agreement 2.56% 9/7/12 9/7/30 36 2 34Sacramento PV Energy Loan Agreement 2.77% 7/26/11 12/31/30 37 2 35Social Security Administration 2.93% 11/01/13 2/18/15 1 – –Continental Wind 6.00% 09/30/13 2/28/33 613 20 593Denver Airport Solar Loan Agreement 5.50% 6/28/11 6/30/31 7 – 7Holyoke Solar Loan Agreement 5.25% 10/25/11 12/31/31 10 – 10AVSR1-Draws 2.33%–3.56% various 1/5/37 447 12 435
Total Non Regulated Business $1,248 $55 $1,191
Notes Payable
Capital Leases $33 $4 $29
Total Long-Term Debt $7,551 $560 $6,990
Maturities 2014 2015 2016 2017 2018
$520 $551 $77 $701 $–
(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.
*Please refer to the 2013 10K for Unamortized Debt Discounts/Premiums and Fair Value Adjustments
7 Long-Term Debt Outstanding as of December 31, 2013
ComEd Interest Date Maturity Total Debt Current Long-TermSeries Rate Issued Date Outstanding Portion Debt
(in millions)
First Mortgage Bonds
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 – 500111 1.95% 9/7/11 9/1/16 250 – 250112 3.40% 9/7/11 9/1/21 350 – 350100 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 – 450113 3.80% 10/1/12 10/1/42 350 – 350114 4.60% 8/19/13 8/15/43 350 – 350
Total First Mortgage Bonds $5,545 $617 $4,928
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
Total Long-Term Debt $5,891 $617 $5,274
Note: Amounts may not add due to rounding.
Maturities 2014 2015 2016 2017 2018
$617 $260 $665 $425 $840
*Please refer to the 2013 10-K for Unamortized Debt Discounts/Premiums and Fair Value Adjustments
8 Long-Term Debt Outstanding as of December 31, 2013
PECO Interest Date Maturity Total Debt Current Long-TermSeries Rate Issued Date Outstanding Portion Debt
(in millions)
First Mortgage Bonds (FMB) FMB 5.00% 3/26/09 10/1/14 250 $250 $– FMB 5.35% 3/3/08 3/1/18 500 – 500FMB 2.38% 9/17/12 9/15/22 350 – 350FMB 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 – 175FMB 1.20% 9/23/13 10/15/16 300 – 300FMB 4.80% 9/23/13 10/15/43 250 – 250
Total First Mortgage Bonds $2,200 $250 $1,950
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
Total Long-Term Debt $2,384 $250 $2,134
Maturities 2014 2015 2016 2017 2018
$250 – $300 – $500
*Please refer to the 2013 10-K for Unamortized Debt Discounts/Premiums and Fair Value Adjustments
9 Long-Term Debt Outstanding as of December 31, 2013
BGE
Interest Date Maturity Debt Current Long-TermSeries Rate Issued Date Outstanding Portion Debt
(in millions)
Senior Notes 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 – 300Senior Notes due 8/15/22 2.80% 8/17/12 8/15/22 250 – 250Senior 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 – 400Notes due 7/1/23 3.35% 6/17/13 7/1/23 300 – 300
Total Senior Notes $1,750 $– $1,750
Rate Stabilization Bonds BGE Securitization due 2017 5.72%–5.82% 6/28/07 4/1/17 $265 $70 $195
Total Rate Stabilization Bonds $265 $70 $195
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
Total Long-Term Debt $2,273 $70 $2,203
Maturities 2014 2015 2016 2017 2018
$– $– $300 $265 $–
*Please refer to the 2013 10-K for Unamortized Debt Discounts/Premiums and Fair Value Adjustments
10 Federal Regulation
Federal Energy Regulatory Commission (FERC)(www.ferc.gov)
The FERC has five full-time members, each appointed by the President of the United States and confirmed by the U.S. Senate. The Commissioners serve for staggered five-year terms. No more than three Commissioners may belong to the same political party. The Chairman is designated by the President.
Commissioner Party Affiliation Service Began Term Ends Professional Experience
Cheryl A. LaFleur Democrat 7/10 6/14 Attorney; executive vice president and acting(Acting Chairman) CEO of National Grid USA; member of the NARUC Committees on Electricity and Critical Infrastructure
Philip D. Moeller Republican 7/06 6/15 Energy policy advisor to former U.S. Senator Slade Gorton (WA); staff coordinator for the WA State Senate Committee on Energy, Utilities and Telecommunications; Alliant Energy Corporation
Tony Clark Republican 6/12 6/16 Chairman of North Dakota Public ServiceCommission; President of NARUC; North Dakota Labor Commissioner under Gov. Ed Schafer; State Legislator; Chairman of Frontier Trails District of the Boy Scouts of America
John R. Norris Democrat 1/10 6/17 Attorney; Chief of Staff to Secretary Tom Vilsack of the U.S. Department of Agriculture; Chairman of the Iowa Utilities Board; President of the Organization of MISO States
Open – pending nomination and approval
ComEd Electric Transmission Rate Cases(a)
Revenue Overall Rate Return on($ in millions) Date Adjustment Test Year Rate Base of Return Equity Equity Ratio
ComEd Update 4/16/14 $22 2013 pro forma $2,358 8.62% 11.50% 55%ComEd Update 4/29/13 $68 2012 pro forma $2,184 8.70% 11.50% 55%ComEd Update 5/15/12 $23 2011 pro forma $2,104 8.91% 11.50% 55%
ComEd Update 5/16/11 $6 2010 pro forma $2,054 9.10% 11.50% 55%ComEd Update 5/14/10 $(24) 2009 pro forma $1,949 9.27% 11.50% 56%
(a) Annual update filing based on the formula rate, originally implemented effective May 1, 2007. Rate effective June 1 of the update year through May 31 of the following year.
BGE Electric Transmission Rate Cases(a)(b)
Revenue Overall Rate Return on($ in millions) Date Adjustment Test Year Rate Base of Return Equity Equity Ratio
BGE Update 4/28/14 $14 2013 pro forma $600 8.53% 11.30% 51.9%BGE Update 4/25/13 $(1) 2012 pro forma $564 8.35% 11.30% 48.6%BGE Update 4/24/12 $18 2011 pro forma $572 8.43% 11.30% 50.0%BGE Update 4/29/11 $(1) 2010 pro forma $501 8.96% 11.30% 53.0%
(a) Annual update filing based on the formula rate, originally implemented effective June 1, 2005. Rate effective June 1 of the update year through May 31 of the following year.
BGE Electric Transmission Rate Cases(a)(b)
Revenue Overall Rate Return on($ in millions) Date Adjustment Test Year Rate Base of Return Equity Equity Ratio
BGE Update 4/28/14 $14 2013 pro forma $600 8.53% 11.30% 51.9%BGE Update 4/25/13 $(1) 2012 pro forma $564 8.35% 11.30% 48.6%BGE Update 4/24/12 $18 2011 pro forma $572 8.43% 11.30% 50.0%BGE Update 4/29/11 $(1) 2010 pro forma $501 8.96% 11.30% 53.0%
(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) 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.
11 State Regulation – ComEd
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 1/19(1) 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 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 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
(1) Chairman Scott has been named to a 2nd term, pending confirmation by the Illinois State Senate
12 State Regulation – ComEd (continued)
ComEd Electric Distribution Rate Cases
Revenue Overall Rate of ($ in millions) Date Increase Test Year Rate Base Return Equity Equity Ratio
Formula Rate Filing(b) 4/16/14 $275 2013 $7,389 7.04% 9.20% 45.77%
Formula Rate Filing(c) 4/29/13 $311 2012 $6,731 7.01% 8.72% 44.99%
Senate Bill 9 Updated Filing(d) 6/5/13 $359 2012 $6,717 6.91% 8.71% 45.28%ICC Order(e) 12/18/13 $341 2012 $6,702 6.94% 8.72% 45.28%
Formula Rate Filing 4/30/12 $74 2011 $6,367 7.58% 9.81% 42.55%
ICC Order 12/19/12 $73(f) 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 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 10/17/07 $345 2006 $6,753 8.57% 10.75% 45.04%ICC Order 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’s initial filing on April 16, 2014. Rate of Return on Equity and Equity Ratio reflect the reconciliation year amounts.
(c) Reflects ComEd’s initial filing on April 29, 2013. Rate of Return on Equity and Equity Ratio reflect the reconciliation year amounts.(d) Reflects ComEd’s updated filing on June 5, 2013 to reflect changes applicable to Senate Bill 9. Rate of Return on Equity and Equity Ratio reflect the reconciliation year amounts.
(e) Reflects ComEd’s Compliance filing in Docket 13-0318. Rate base reflects filing year amounts. Rate of Return, Return on Equity, and Equity Ratio reflect the reconciliation year amounts.
(f) ComEd updated 2013 rates as a result of SB9 and Docket No. 13-0286. The update reduced the total rev req increase in 2013 rates to $59M.
ComEd – Average Total Residential Rate
($/MWh)Year Transmission Distribution Energy Other(a) Total
2011 $7.49 41.40 73.14 3.78 125.81
2012 $7.98 42.70 70.13 4.72 125.53
2013 $8.92 41.79 59.60 3.67 113.98
(a) Primarily includes taxes and environmental cost recovery and energy efficiency riders.
13 State Regulation – PECO
Pennsylvania Public Utility Commission (PUC)(www.puc.state.pa.us)
The PUC has five full-time members, each appointed by the Governor (currently Tom Corbett, Republican; term began in January 2011 and ends in January 2015) and confirmed by the Pennsylvania State Senate. The Commissioners serve for staggered five-year terms. Under Pennsylvania law, no more than three Commissioners may belong to the same political party as the Governor. The Chairman is designated by the Governor, and the Vice Chairman is selected by the PUC commissioners.
Commissioner Party Affiliation Service Began Term Ends Professional Experience
Robert F. Powelson (Chairman) Republican 6/08 4/19 President/CEO of Chester County Chamber of Business and Industry; staff assistant to former U.S. Representative Curt Weldon (PA)
John F. Coleman Jr. Republican 6/10 4/17 President/CEO of Centre County Chamber (Vice Chairman) of Business and Industry; Executive Director of the Jefferson County Department of Development
Pamela A. Witmer Republican 6/11 4/16 Energy and environment practice lead at Bravo Group. President and CEO of Pennsylvania Chemical Industry Council; lead legislative liaison in PA Department of Environmental Protection; research analyst for PA House of Representatives
Gladys M. Brown Democrat 6/13 4/18 Counsel to the Senate Democratic Leadership
James H. Cawley Democrat 6/05 4/15 Attorney; majority counsel to the Pennsylvania Senate Consumer Affairs Committee
PECO Electric Distribution Rate Case
Revenue Overall Rate Return on ($ in millions) Date Increase Test Year Rate Base of Return 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 $225 2010 n/a n/a n/a n/a
PECO Gas Delivery Rate Cases
Revenue Overall Rate Return on ($ in millions) Date Increase Test Year Rate Base of Return 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) Energy Efficiency Energy and
Year Transmission Distribution Surcharge CTC(c) Capacity Total
2011 6.90 58.40 4.70 – 84.00 154.002012 8.04 59.95 2.42 – 88.52 158.93
2013 8.33 59.67 3.05 – 82.49 153.54
(a) The PUC authorized recovery in PECO’s 1998 settlement of competitive transition charges (CTC) through 2010.
State Regulation – BGE
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 6/18 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
Anne Hoskins Democrat 8/13 6/16 Senior vice president of public affairs and sustainability for Public Service Enterprise; Senior counsel at Verizon Wireless from 2000 to 2007; a regulatory counsel at Verizon (Bell Atlantic- New York) from 1998 to 2000; associate attorney at McCarter and English, a New Jersey law firm, from 1995 to 1998; attorney at the U.S. Office of the Comptroller of the Currency from 1994 to 1995;Public Capital Program Coordinator at the Center for Policy Alternatives from 1989 to 1991; policy advisor in the New Jersey Governor’s Office of Policy and Planning from 1986 to 1989.
BGE Electric Distribution Rate Case
Revenue Adjusted Overall Rate Return on ($ in millions) Date Increase Test Year Rate Base of Return Equity Equity Ratio
BGE Request 5/17/13 $82.6 2012-13 $2.823 7.75% 10.5% 51.10%PSC Order 12/13/13 $33.6 2012-13 $2.753 7.49% 9.75% 51.10%
BGE Request 7/27/12 $130 2011-12 $2.710 7.96% 10.50% 48.40%PSC Order 2/22/13 $81 2011-12 $2.635 7.60% 9.75% 48.40%
BGE Gas Distribution Rate Case
Revenue Adjusted Overall Rate Return on ($ in millions) Date Increase Test Year Rate Base of Return Equity Equity Ratio
BGE Request 5/17/13 $24.4 2012-13 $1.050 7.61% 10.35% 51.10%PSC Order 12/13/13 $12.2 2012-13 $1.027 7.41% 9.60% 51.10%
BGE Request 7/27/12 $46 2011-12 $1.014 7.96% 10.50% 48.40%PSC Order 2/22/13 $32 2011-12 $976 7.53% 9.60% 48.40%
BGE Request 5/7/10 $30 2009-10 $839 8.99% 11.65% 51.93%
PSC Order 12/6/10 $10 2009-10 $817 7.90% 9.56% 51.93%
BGE – Average Total Residential Rate ($/MWh)
Year Energy Transmission Distribution Other(a) Total
2011 93.39 6.13 33.05 4.33 136.902012 85.54 7.87 33.35 4.78 131.54
2013 88.01 7.84 37.22 5.16 138.24
(a) Includes EmPowerMD Charge, RSP Charge/Misc Credits, taxes, and other surcharges.
14
Capital Structure and Capitalization Ratios for Exelon and Operating Companies
(at December 31) 2013 2012 2011
Exelon (consolidated) (in millions) (in percent) (in millions) (in percent) (in millions) (in percent)
Total Debt $20,121 46.7 $19,603 47.3 $13,405 48.1
Preferred Securities of Subsidiaries – – 87 0.2 87 0.3
Total Equity 22,940 53.3 21,730 52.5 14,388 51.6
Total Capitalization $43,061 $41,420 $27,880
Exelon Generation Total Debt $7,751 37.8 $7,483 37.1 $3,679 29.7
Total Equity 12,742 62.2 12,665 62.9 8,708 70.3
Total Capitalization $20,493 $20,148 $12,387
ComEd Total Debt $6,065 44.6 $5,773 44.1 $5,871 45.5 Total Shareholders’ Equity 7,528 55.4 7,323 55.9 7,037 54.5
Total Capitalization $13,593 $13,096 $12,908
PECO Total Debt $2,381 43.7 $2,341(a) 43.3 $2,381(a) 44.0
Preferred Securities (b) – – 87 1.6 87 1.6 Total Shareholders’ Equity 3,065 56.3 2,982 55.1 2,938 54.3
Total Capitalization $5,446 $5,410 $5,406
Transition Debt $–
BGE(c) Total Debt $2,404 48.5 $2,436 50.8 n/a n/a
Preferred Securities 190 3.8 190 4.0 n/a n/a Total Shareholders’ Equity 2,365 47.7 2,168 45.2 n/a n/a
Total Capitalization $4,959 $4,794 n/a
Note: Percentages may not add due to rounding.
(a) Includes PECO’s accounts receivable agreement at December 31, 2012 and 2011 of $210 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 2011.
15
16 Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations (unaudited)
Exelon Corporation Twelve Months Ended December 31, 2013 Twelve Months Ended December 31, 2012(a)
(in millions, Adjusted Adjusted
except per share data) GAAP(b) Adjustments Non-GAAP GAAP(b) Adjustments Non-GAAPP
Operating revenues $24,888 $ 541(c),(d) $ 25,442 $ 23,489 $1,185(c),(d),(e),(n) $24,674
Operating expenses Purchased power and fuel 9,468 563(c),(d) 11,300 10,157 607(c),(d),(e),(f) 10,764
Operating and maintenance 7,270 (312)(e),(f),(g),(h),(i) 6,958 7,961 (1,182)(d),(e),(f),(h), 6,779
Depreciation, amortization 2,153 (5)(e),(f) 2,148 1,881 (47)(e),(f) 1,834
Taxes other than income 1,095 – 1,095 1,019 (9)(e),(f),(n) 1,010
Total operating expenses 21,255 246 21,501 21,018 (631) 20,387
Equity in earnings (loss) of unconsolidated affiliates 10 92(d),(f) 102 (91) 150(d),(f) 59
Operating income 3,656 387 4,043 2,380 1,966 4,346
Other income and (deductions) Interest expense (1,356) 370(f),(g),(j),(k) (986) (928) (13)(f),(j) (941)
Other, net 473 (235)(e),(f),(j),(l) 238 346 (94)(e),(f),(l) 252
Total other income and (deductions) (883) 135 (748) (582) (107) (689)
Income before income taxes 2,773 522 3,295 1,798 1,859 3,657
Income taxes 1,044 88(i),(j),(k),(l),(m) 1,132 627 689(j),(i),(l),(m),(n),(o) 1,316
Net income 1,729 434 2,163 1,171 1,170 2,341
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends 10 4(g) 14 11 – 11
Net income attributable to common shareholders $1,719 $430 $2,149 $1,160 $1,170 $ 2,330
Effective tax rate 37.6% 34.4% 34.9% 36.0%
Earnings per average common share Basic $ 2.01 $ 0.50 $ 2.51 $ 1.42 $1.43 $ 2.85
Diluted $ 2.00 $ 0.50 $ 2.50 $ 1.42 $1.43 $ 2.85
Average common shares outstanding Basic 856 856 816 816
Diluted 860 860 819 819
(i),(l),(m),(n),(o)
(c),(d),(e),(f),(g),(h)
(c),(d),(e),(f),(h),
17 Reconciliation of Adjusted (non-GAAP) Operating Earningsto GAAP Consolidated Statements of Operations (unaudited)
Exelon Corporation (continued)
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2013 2012
Mark-to-market impact of economic hedging activities(c) $(0.35) $(0.38)
Amortization of commodity contract intangibles(d) 0.41 0.93
Plant retirements and divestitures(e) (0.02) 0.29
Merger and integration costs(f) 0.08 0.31
Long-lived asset impairment(g) 0.14 –
Asset retirement obligation(h) 0.01 –
Midwest Generation bankruptcy charges(i) 0.02 0.01
Amortization of the fair value of certain debt(j) (0.01) (0.01)
Remeasurement of like-kind exchange tax position(k) 0.31 –
Unrealized gains related to NDT fund investments(l) (0.09) (0.07)
Reassessment of state deferred income taxes(m) – (0.14)
Maryland commitments(n) – 0.28
FERC settlement(o) – 0.21
Total adjustments $ 0.50 $ 1.43
(a) For the twelve months ended December 31, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.
(b) Results reported in accordance with GAAP.
(c) Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.
(d) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.
(e) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.
(f) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, certain pre-acquisition contingencies and CENG transaction costs.
(g) Adjustment to exclude the impairment of the cancellation of previously capitalized nuclear uprate projects and the impairment of certain wind generating assets.
(h) Adjustment in 2013 to exclude an increase in Generation’s asset retirement obligation primarily for asbestos at retired fossil power plants, and in 2012 to exclude a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generation stations.
(i) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.
(j) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.
(k) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.
(l) Adjustment to exclude the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.
(m) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.
(n) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.
(o) Adjustment to exclude costs associated with a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.
18 Reconciliation of Adjusted (non-GAAP) Operating Earningsto GAAP Consolidated Statements of Operations (unaudited)
Exelon Generation Twelve Months Ended December 31, 2013 Twelve Months Ended December 31, 2012(a)
Adjusted Adjusted
(in millions) GAAP(b) Adjustments Non-GAAP GAAP(b) Adjustments Non-GAAPP
Operating revenues $15,630 $547(c),(d) $16,190 $14,437 $1,065(c),(d),(i) $15,502
Operating expenses Purchased power and fuel 8,197 563(c),(d) 8,773 7,061 607(c),(d),(e),(i) 7,668
Operating and maintenance 4,534 (285)(e),(f),(g),(h),(i) 4,249 5,028 (889)(i),(m),(n) 4,139
Depreciation, amortization, accretion and depletion 856 (5)(e),(i) 851 768 (47)(e),(i) 721
Taxes other than income 389 – 389 369 (11)(i) 358
Total operating expenses 13,989 273 14,262 13,226 (340) 12,886
Equity in earnings of unconsolidated affiliates 10 92(d),(e) 102 (91) 150(d),(e) 59
Operating income 1,664 366 2,030 1,120 1,555 2,675
Other income and deductions Interest expense (357) 2(e),(f),(l) (355) (301) (16)(l) (317)
Other, net 368 (235)(e),(i),(j),(l) 133 239 (94)(e),(i),(j) 145
Total other income and deductions 11 (233) (222) (62) (110) (172)
Income before income taxes 1,675 133 1,808 1,058 1,445 2,503
Income taxes 615 (3)(h),(i),(j),(k),(l) 612 500 459(i),(j),(k),(l),(m),(n) 959
Net Income 1,060 136 1,196 558 986 1,544
Net loss attributable to noncontrolling interests (10) 4(f) (6) (4) – (4)
Net income on common stock $ 1,070 $ 132 $ 1,202 $ 562 $986 $ 1,548
(d),(e),(g),(h),
(c),(d),(e),(f),(g),
(c),(d),(e),(g),(h),
(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 the mark-to-market impact of Generation’s economic hedging activities.
(d) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.
(e) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, certain pre-acquisition contingencies, and CENG transaction costs.
(f) Adjustment to exclude the impairment of certain wind generating assets.
(g) Adjustment to exclude Generation’s asset retirement obligation in 2013 primarily for asbestos at retired fossil power plants 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 impacts associated with the sale or retirement of generating stations.
(j) Adjustment to exclude the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.
(k) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.
(l) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.
(m) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.
(n) Adjustment to exclude costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.
19 Reconciliation of Adjusted (non-GAAP) Operating Earningsto GAAP Consolidated Statements of Operations (unaudited)
ComEd Twelve Months Ended December 31, 2013 Twelve Months Ended December 31, 2012
Adjusted Adjusted
(in millions) GAAP(a) Adjustments Non-GAAP GAAP(a) Adjustments Non-GAAPP
Operating revenues $4,464 $ – $4,464 $5,443 $ – $5,443
Operating expenses
Purchased power 1,174 – 1,174 2,307 – 2,307
Operating and maintenance 1,368 (2)(b) 1,366 1,345 (5)(b) 1,340
Depreciation, amortization 669 – 669 610 – 610
Taxes other than income 299 – 299 295 – 295
Total operating expenses 3,510 (2) 3,508 4,557 (5) 4,552
Operating income 954 2 956 886 5 891
Other income and deductions Interest expense (579) 287(c) (292) (307) – (307)
Other, net 26 – 26 39 – 39
Total other income and deductions (553) 287 (266) (268) – (268)
Income before income taxes 401 289 690 618 5 623
Income taxes 152 117(b),(c) 269 239 3(b) 242
Net income $ 249 $ 172 $ 421 $ 379 $ 2 $ 381
(a) Results reported in accordance with GAAP.
(b) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, certain pre-acquisition contingencies and CENG transaction costs.
(c) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.
20 Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations (unaudited)
PECO Twelve Months Ended December 31, 2013 Twelve Months Ended December 31, 2012
Adjusted Adjusted
(in millions) GAAP(a) Adjustments Non-GAAP GAAP(a) Adjustments Non-GAAPP
Operating revenues $3,100 $ – $3,100 $3,186 $ – $3,186
Operating expenses
Purchased power and fuel 1,300 – 1,300 1,375 – 1,375
Operating and maintenance 748 (9)(b) 739 809 (17)(b) 792
Depreciation, amortization 228 – 228 217 – 217
Taxes other than income 158 – 158 162 – 162
Total operating expenses 2,425 (9) 2,434 2,563 (17) 2,546
Operating income 666 9 675 623 17 640
Other income and deductions Interest expense (115) – (115) (123) – (123)
Other, net 6 – 6 8 – 8
Total other income and deductions (109) – (109) (115) – (115)
Income before income taxes 557 9 566 508 17 525
Income taxes 162 4(b) 166 127 7(b) 134
Net Income 395 5 400 381 10 391
Preferred security dividends 7 – 7 4 – 4
Net income on common stock $ 388 $ 5 $ 393 $ 377 $ 10 $ 387
(a) Results reported in accordance with GAAP.
(b) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, certain pre-acquisition contingencies and CENG transaction costs.
21 Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations (unaudited)
BGE Twelve Months Ended December 31, 2013 Twelve Months Ended December 31, 2012
Adjusted Adjusted
(in millions) GAAP(a) Adjustments Non-GAAP GAAP(a) Adjustments Non-GAAPP
Operating revenues $ 3,065 $ – $ 3,065 $ 2,091 $ 113(c) $ 2,204
Operating expenses
Purchased power 1,421 – 1,421 1,052 – 1,052
Operating and maintenance 634 3(b) 637 596 (37)(b),(c) 559 Depreciation, amortization 348 – 348 238 – 238
Taxes other than income 213 – 213 167 2(c) 169
Total operating expenses 2,616 3 2,619 2,053 (35) 2,018
Operating income (loss) 449 (3) 446 38 148 186
Other income and (deductions) Interest expense (122) – (122) (111) – (111)
Other, net 17 – 17 19 – 19
Total other income and (deductions) (105) – (105) (92) – (92)
Income (loss) before income taxes 344 (3) 341 (54) 148 94
Income taxes 134 (1)(b) 133 (23) 60(b),(c) 37
Net income (loss) 210 (2) 208 (31) 88 57
Preference stock dividends 13 – 13 11 – 11
Net income (loss) attributable to common shareholders $ 197 $ (2) $ 195 $ (42) $ 88 $ 46
(a) Results reported in accordance with GAAP.
(b) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, certain pre-acquisition contingencies and CENG transaction costs.
(c) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.
22 Supply and Sales Statistics
Exelon Generation – Annual Electric Supply and Sales Statistics Twelve Months Ended December 31,
(in GWhs) 2013 2012(a)
Supply
Nuclear Generation(b)
Mid-Atlantic 48,881 47,337
Midwest 93,245 92,525
Total Nuclear Generation 142,126 139,862
Fossil and Renewables(b)
Mid-Atlantic(b)(d) 11,714 8,808
Midwest 1,478 971
New England 10,896 9,965
ERCOT 6,453 6,182
Other(e) 6,664 5,913
Total Fossil and Renewables 37,205 31,839
Purchased Power Mid-Atlantic(c) 14,092 20,830
Midwest 4,408 9,805
New England 7,655 9,273
New York(c) 13,642 11,457
ERCOT 15,063 23,302
Other(e) 14,931 17,327
Total Purchased Power 69,791 91,994
Total Supply/Sales by Region(g)
Mid-Atlantic(f) 74,687 76,975
Midwest(f) 99,131 103,301
New England 18,551 19,238
New York 13,642 11,457
ERCOT 21,516 29,484
Other(e) 21,595 23,240
Total Supply/Sales by Region 249,122 263,695
Average Margin ($/MWh)(h)(i)
Mid-Atlantic(j) $43.78 $44.60
Midwest(j) 26.09 29.02
New England 9.97 10.19
New York (0.29) 6.63
ERCOT 20.26 13.74
Other(e) 9.31 5.64 Average Margin – Overall Portfolio $26.79 $27.45
Around-the-clock Market Prices ($/MWh)(k) PJM West Hub $37.33 $33.91
NiHub 31.36 28.97
NEPOOL Mass Hub 2.75 6.06
NYPP Zone A 38.23 31.02
ERCOT North Spark Spread 1.40 3.23
(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 12,067 GWh and 9,925 GWh in the Mid-Atlantic and 12,165 GWh and 9,350 GWh in New York as a result of the PPA with CENG for the years ended December 31, 2013 and 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 2012 as a result of the Exelon and Constellation merger.
(e) Other Regions includes South, West and Canada, which are not considered individually significant.
(f) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(g) Total sales do not include physical proprietary trading volumes of 8,762 GWh, 5,742 GWh and 3,625 GWh for the years ended December 31, 2013, 2012 and 2011, respectively.
(h) 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.
(i) Excludes the mark-to-market impact of Generation’s economic hedging activities.
(j) 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.
(k) Represents the average for twelve months ended December 31, 2013 and 2012.
23 Supply and Sales Statistics
Exelon Generation – Electric Supply and Sales by Quarter Three Months Ended
December 31, September 30, June 30, March 31, December 31,(in GWhs) 2013 2013 2013 2013 2012
Supply Nuclear Generation(a) Mid-Atlantic 11,900 12,424 11,794 12,762 11,547
Midwest 23,429 23,741 22,807 23,269 23,335
Total Nuclear Generation 35,329 36,165 34,601 36,031 34,882
Fossil and Renewables(a) Mid-Atlantic(a)(c) 2,951 2,808 2,796 3,160 2,154
Midwest 363 217 318 581 300
New England 1,763 3,609 3,132 2,392 2,368
ERCOT 1,582 2,522 1,617 733 755
Other(d) 1,064 1,913 1,431 2,254 1,358
Total Fossil and Renewables 7,723 11,069 9,294 9,120 6,935
Purchased Power Mid-Atlantic(b) 3,955 4,289 2,616 3,233 4,332
Midwest 498 707 1,503 1,700 2,661
New England 2,605 2,178 1,365 1,507 2,304
New York(b) 3,493 3,565 3,073 3,511 3,678
ERCOT 2,792 3,803 4,269 4,199 6,043
Other(d) 2,986 3,244 4,998 3,703 4,172
Total Purchased Power 16,329 17,786 17,824 17,853 23,190
Total Supply/Sales by Region(f) Mid-Atlantic(e) 18,806 19,521 17,206 19,155 18,033
Midwest(e) 24,290 24,665 24,628 25,550 26,296
New England 4,368 5,787 4,497 3,899 4,672
New York 3,493 3,565 3,073 3,511 3,678
ERCOT 4,374 6,325 5,886 4,932 6,798
Other(d) 4,050 5,157 6,429 5,957 5,530
Total Supply/Sales by Region 59,381 65,020 61,719 63,004 65,007
(a) 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).
(b) Purchased power includes physical volumes of 3,226 GWhs, 3,138 GWhs, 3,114 GWhs, 2,588 GWhs, and 3,255 GWhs in the Mid-Atlantic and 3,051 GWhs, 3,147 GWhs, 2,655 GWhs, 3,213 GWhs, and 2,814 GWhs in New York as a result of the PPA with CENG for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 2012, respectively.
(c) Excludes 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.
(d) Other Regions includes South, West and Canada, which are not considered individually significant.
(e) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(f) Total sales do not include physical trading volumes of 2,696 GWhs, 2,499 GWhs, 1,995 GWhs, 1,572 GWhs, and 2,977 GWhs, for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 2012, and respectively.
(g) 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 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.
(h) Excludes the mark-to-market impact of Generation’s economic hedging activities.
(i) 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.
(j) Represents the average for the quarter.
(k) Outage days exclude Salem and CENG.
24 Supply and Sales Statistics
Exelon Generation – Electric Supply and Sales by Quarter (continued) Three Months Ended
December 31, September 30, June 30, March 31, December 31, 2013 2013 2013 2013 2012
Average Margin ($/MWh)(g)(h)
Mid-Atlantic(i) $42.38 $44.26 $44.64 $44.04 $48.24
Midwest(i) 24.00 24.37 27.77 28.08 26.09
New England 9.62 10.71 11.12 7.63 3.64
New York 3.72 (2.52) 4.56 (6.27) 4.35
ERCOT 18.06 22.77 19.03 20.54 13.39
Other(d) 13.58 7.95 9.18 7.61 7.96
Average Margin – Overall Portfolio $26.42 $26.19 $27.33 $27.23 $26.52
Around-the-clock Market Prices ($/MWh)(j) PJM West Hub $35.70 $38.79 $37.63 $37.53 $35.94
NiHub 29.94 32.88 31.77 30.93 28.37
New England Mass Hub ATC Spark Spread 1.33 12.56 4.96 (6.63) 3.07
NYPP Zone A 38.23 39.75 34.38 40.23 34.70
ERCOT North Spark Spread 2.09 4.39 (0.20) (0.66) (0.27)
Three Months Ended
December 31, September 30, June 30, March 31, December 31, 2013 2013 2013 2013 2012
Outage Days(k) Refueling 94 43 47 49 113
Non-refueling 33 5 31 6 1
Total Outage Days 127 48 78 55 114
(a) 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).
(b) Purchased power includes physical volumes of 3,226 GWhs, 3,138 GWhs, 3,114 GWhs, 2,588 GWhs, and 3,255 GWhs in the Mid-Atlantic and 3,051 GWhs, 3,147 GWhs, 2,655 GWhs, 3,213 GWhs, and 2,814 GWhs in New York as a result of the PPA with CENG for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 2012, respectively.
(c) Excludes 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.
(d) Other Regions includes South, West and Canada, which are not considered individually significant.
(e) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(f) Total sales do not include physical trading volumes of 2,696 GWhs, 2,499 GWhs, 1,995 GWhs, 1,572 GWhs, and 2,977 GWhs, for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 2012, and respectively.
(g) 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 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.
(h) Excludes the mark-to-market impact of Generation’s economic hedging activities.
(i) 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.
(j) Represents the average for the quarter.
(k) Outage days exclude Salem and CENG.
25 Supply and Sales Statistics
ComEd – Electric Sales Statistics, Revenue and Customer Detail Three Months Ended December 31, 2013 and 2012
Electric Deliveries (in GWhs) Revenue (in millions)
Weather- Normal
2013 2012 % Change % Change 2013 2012 % Change
Retails Deliveries and Sales(a)
Residential 6,646 6,183 7.5% 2.0% $485 $665 (27.1)%
Small Commercial & Industrial 7,920 7,792 1.6% (0.7)% 303 342 (11.4)%
Large Commercial & Industrial 6,752 6,595 2.4% (0.0)% 100 99 1.0%
Public Authorities & Electric Railroads 358 340 5.3% (1.6)% 13 13 0.0%
Total Retail 21,676 20,910 3.7% 0.4% 901 1,119 (19.5)%
Other Revenue(b) 167 170 (1.8)%
Total Electric Revenue $1,068 $1,289 (17.1)% Purchased Power $243 $421 (42.3)%
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 2,487 2,030 2,293 22.5% 8.5%
Cooling Degree-Days 25 3 11 733.3% 127.3%
Twelve Months Ended December 31, 2013 and 2012
Electric Deliveries (in GWhs) Revenue (in millions)
Weather- Normal
2013 2012 % Change % Change 2013 2012 % Change
Retails Deliveries and Sales(a)
Residential 27,800 28,528 (2.6)% (0.0)% $2,073 $3,037 (31.7)%
Small Commercial & Industrial 32,305 32,534 (0.7)% (0.5)% 1,250 1,339 (6.6)%
Large Commercial & Industrial 27,684 27,643 0.1% (0.3)% 427 395 8.1%
Public Authorities & Electric Railroads 1,355 1,272 6.5% 8.2% 48 44 9.1%
Total Retail 89,144 89,977 (0.9)% (0.2)% 3,798 4,815 (21.1)%
Other Revenue(b) 666 628 6.1%
Total Electric Revenue $4,464 $5,443 (18.0)% Purchased Power $1,174 $2,307 (49.1)%
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 6,603 5,065 6,341 30.4% 4.1%
Cooling Degree-Days 933 1,324 842 (29.5)% 10.8%
Number of Electric Customers 2013 2012
Residential 3,480,398 3,455,546
Small Commercial & Industrial 367,596 365,357
Large Commercial & Industrial 1,984 1,980
Public Authorities & Electric Railroads 4,853 4,812
Total 3,854,804 3,827,695
(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 rental revenues, revenues related to late payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and intercompany revenues.
26 Supply and Sales Statistics
PECO– Electric Sales Statistics, Revenue and Customer Detail Three Months Ended December 31, 2013 and 2012
Electric and Gas Deliveries Revenue (in millions)
Weather- Normal
2013 2012 % Change % Change 2013 2012 % Change
Electric (in GWhs)
Retails Deliveries and Sales(a)
Residential 3,207 3,079 4.1% (0.3)% $395 $392 0.8%
Small Commercial & Industrial 1,990 1,908 4.3% 0.8% 109 105 3.8%
Large Commercial & Industrial 3,742 3,708 0.9% (0.4)% 51 53 (3.8)%
Public Authorities & Electric Railroads 218 229 (4.9)% (4.9)% 7 7 0.0%
Total Retail 9,157 8,924 2.6% (0.3)% 562 557 0.9%
Other Revenue(b) 60 54 11.1%
Total Electric Revenue 622 611 1.8%
Gas (in mmcfs)
Retails Deliveries and Sales
Retail Sales(c) 18,725 17,466 7.2% 0.8% 176 165 6.7%
Transportation and Other 7,209 7,209 (1.1)% (4.1)% 7 14 (50.0)%
Total Gas 25,934 24,756 4.8% (0.6)% 183 179 2.2%
Total Electric and Gas Revenues 805 790 1.9%
Purchased Power and Fuel 347 342 1.5%
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 1,577 1,482 1,629 6.4% (3.2)%
Cooling Degree-Days 65 31 19 109.7% 242.1%
(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) 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.
27 Supply and Sales Statistics
PECO – Electric Sales Statistics, Revenue and Customer Detail Twelve Months Ended December 31, 2013 and 2012
Electric and Gas Deliveries Revenue (in millions)
Weather- Normal
2013 2012 % Change % Change 2013 2012 % Change
Electric (in GWhs)
Retails Deliveries and Sales(a)
Residential 13,341 13,233 0.8% (0.0)% $1,592 $1,689 (5.7)%
Small Commercial & Industrial 8,101 8,063 0.5% (1.1)% 433 462 (6.3)%
Large Commercial & Industrial 15,379 15,253 0.8% 1.5% 224 232 (3.4)%
Public Authorities & Electric Railroads 930 943 (1.4)% (1.4)% 30 31 (3.2)%
Total Retail 37,751 37,492 0.7% 0.3% 2,279 2,414 (5.6)%
Other Revenue(b) 221 226 (2.2)%
Total Electric Revenue 2,500 2,640 (5.3)%
Gas (in mmcfs)
Retails Deliveries and Sales
Retail Sales(c) 57,613 49,767 15.8% (0.1)% 562 509 10.4%
Transportation and Other 28,089 26,687 5.3% 0.5% 38 37 2.7%
Total Gas 85,702 76,454 12.1% 0.1% 600 546 9.9%
Total Electric and Gas Revenues $3,100 3,186 (2.7)%
Purchased Power and Fuel $1,300 1,375 (5.5)%
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 4,474 3,747 4,603 19.4% (2.8)%
Cooling Degree-Days 1,411 1,603 1,301 (12.0)% 8.5%
Number of Electric Customers 2013 2012 Number of Gas Customers 2013 2012
Residential 1,423,068 1,417,773 Residential 458,356 454,502
Small Commercial & Industrial 149,117 148,803 Commercial & Industrial 42,174 41,836
Large Commercial & Industrial 3,105 3,111 Total Retail 500,530 496,338
Public Authorities & Electric Railroads 9,668 9,660 Transportation 909 903
Total 1,584,958 1,579,347 Total 501,439 497,241
(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) 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.
28 Supply and Sales Statistics
BGE – Electric Sales Statistics, Revenue and Customer Detail
Three Months Ended December 31, 2013 and 2012
Electric and Gas Deliveries Revenue (in millions)
2013 2012 % Change 2013 2012 % Change
Electric (in GWhs)
Retails Deliveries and Sales(a)
Residential 3,227 3,026 6.6% $347 $314 10.5%
Small Commercial & Industrial 735 674 9.1% 60 55 9.1%
Large Commercial & Industrial 3,293 3,378 (2.5)% 106 91 16.5%
Public Authorities & Electric Railroads 78 80 (2.5)% 8 7 14.3%
Total Retail 7,333 7,158 2.4% 521 467 11.6%
Other Revenue(b) 71 62 14.5%
Total Electric Revenue 592 529 11.9%
Gas (in mmcfs)
Retails Deliveries and Sales(c)
Retail Sales 28,166 26,333 7.0% 180 159 13.2%
Transportation and Other(d) 4,082 3,145 29.8% 22 15 46.7%
Total Gas 32,248 29,478 9.4% 202 174 16.1%
Total Electric and Gas Revenues 794 703 12.9%
Purchased Power and Fuel 362 326 11.0%
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 1,690 1,616 1,678 4.6% 0.7%
Cooling Degree-Days 39 25 26 56.0% 50.0%
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.
(b) Other revenue includes wholesale transmission revenue and late payment charges.
(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.
(d) Transportation and other gas revenue includes off-system revenue of 4,082 mmcfs ($19 million) and 3,145 mmcfs ($14 million) for the three months ended December 31, 2013 and 2012, respectively, and 12,210 mmcfs ($55 million) and 12,221 mmcfs ($40 million) for the twelve months ended December 31, 2013 and from March 12, 2012 through December 31, 2012, respectively.
29 Supply and Sales Statistics
BGE – Electric Sales Statistics, Revenue and Customer Detail
Twelve Months Ended December 31, 2013 and 2012
Electric and Gas Deliveries Revenue (in millions)
2013 2012 % Change 2013 2012 % Change
Electric (in GWhs)
Retails Deliveries and Sales(a)
Residential 13,077 12,719 n.m. $1,404 $996 n.m.
Small Commercial & Industrial 3,035 2,990 n.m. 257 197 n.m.
Large Commercial & Industrial 14,339 14,956 n.m. 439 318 n.m.
Public Authorities & Electric Railroads 317 329 n.m. 31 25 n.m.
Total Retail 30,768 30,994 n.m. 2,131 1,536 n.m.
Other Revenue(b) 274 198 n.m.
Total Electric Revenue 2,405 1,734 n.m.
Gas (in mmcfs)
Retails Deliveries and Sales(c)
Retail Sales 94,020 86,945 n.m. 592 312 n.m.
Transportation and Other(d) 12,210 15,751 n.m. 68 45 n.m.
Total Gas 106,230 102,697 n.m. 660 357 n.m.
Total Electric and Gas Revenues $3,065 2,091 n.m.
Purchased Power and Fuel $1,421 1,052 n.m.
% Change
Heating and Cooling Degree-Days 2013 2012 Normal From 2012 From Normal
Heating Degree-Days 4,744 3,804 4,661 n.m. 1.8%
Cooling Degree-Days 869 1,012 864 n.m. 0.6%
Number of Electric Customers 2013 2012 Number of Gas Customers 2013 2012
Residential 1,120,431 1,116,233 Residential 611,532 610,827
Small Commercial & Industrial 112,850 112,994 Commercial & Industrial 44,162 44,228
Large Commercial & Industrial 11,652 11,580 Total Retail 655,694 655,055
Public Authorities & Electric Railroads 292 319 Transportation – –
Total 1,245,225 1,241,126 Total 655,694 655,055
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.
(b) Other revenue includes wholesale transmission revenue and late payment charges.
(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.
(d) Transportation and other gas revenue includes off-system revenue of 4,082 mmcfs ($19 million) and 3,145 mmcfs ($14 million) for the three months ended December 31, 2013 and 2012, respectively, and 12,210 mmcfs ($55 million) and 12,221 mmcfs ($40 million) for the twelve months ended December 31, 2013 and from March 12, 2012 through December 31, 2012, respectively.
30 Exelon Generation – Total Owned Generating Capacity
Owned net electric generating capacity by station at December 31, 2013:
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.
Net Primary Generation Number Percent Primary Dispatch Capacity(b)
Station Location of Units Owned(a) Fuel Type Type (MW)
Nuclear
Braidwood Braidwood, IL 2 100 Uranium Base-load 2,353
Byron Byron, IL 2 100 Uranium Base-load 2,319
Calvert Cliffs(d) Lusby, MD 2 50.01 Uranium Base-load 878
Clinton Clinton, IL 1 100 Uranium Base-load 1,067
Dresden Morris, IL 2 100 Uranium Base-load 1,843
LaSalle Seneca, IL 2 100 Uranium Base-load 2,327
Limerick Sanatoga, PA 2 100 Uranium Base-load 2,316
Nine Mile Point(d) Scriba, NY 2 50.01 Uranium Base-load 833
Oyster Creek Forked River, NJ 1 100 Uranium Base-load 625(c)
Peach Bottom Delta, PA 2 50.00 Uranium Base-load 1,167(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 Lower Alloways Creek Twp., NJ 2 42.6 Uranium Base-load 1,006(d)
Three Mile Island Middletown, PA 1 100 Uranium Base-load 837
19,262
Fossil (Combined Cycle Gas Turbines)
Colorado Bend Wharton, TX 6 Gas Intermediate 498 Fore River North Weymouth, MA 3 Gas Intermediate 726 Hillabee Alexander City, AL 3 Gas Intermediate 670 Mystic 8/9 Charlestown, MA 6 Gas Intermediate 1,418 Quail Run Odessa, TX 6 Gas Intermediate 488 Wolf Hollow Granbury, TX 3 Gas Intermediate 705
4,505
31 Owned net electric generating capacity by station at December 31, 2013:
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 33
Grande Prairie Alberta, Canada 1 Gas Peaking 75
Handsome Lake Rockland Twp., PA 5 Gas Peaking 268
LaPorte Laporte, TX 4 Gas Peaking 152
Medway West Medway, MA 3 Oil/Gas Peaking 117
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 16
Notch Cliff Baltimore Co., MD 8 Gas Peaking 118
Perryman Harford Co., MD 5 Oil/Gas Peaking 353
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 52West Valley Salt Lake City, UT 5 Gas Peaking 185Westport-5 Baltimore Co., MD 1 Gas Peaking 116
2,797
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 198
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 8
Exelon Generation – Total Electric Generating Capacity (continued)
32 Owned net electric generating capacity by station at December 31, 2013: (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 69Michigan Wind II Minden City, MI 50 Wind Base-load 90Mountain Home Elsmore Co., ID 20 Wind Base-load 42Muddy Run Lancaster Co., PA 8 Hydro Intermediate 1,070Norgaard Lincoln Co., MN 7 99.0 Wind Base-load 9(d)
Pennsbury Falls Twp., PA 2 Landfill Gas Peaking 6Safe 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)
3,629
Exelon Generation – Total Owned Generating Capacity (continued)
33 Owned net electric generating capacity by station at December 31, 2013: (continued)
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 575
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)
4,909
Total Owned Generation (in MW) 35,109
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. Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2.
(e) Constellation Solar is an operation that constructs, owns and operates solar facilities at various customer locations.
Exelon Generation – Total Electric Generating Capacity (continued)
34 Exelon Generation – Nuclear Generating Capacity
Exelon Nuclear Fleet(a)(b)
Nuclear Operating Data(a)
2013 2012 2011
Fleet capacity factor 94.1% 92.7% 93.3% Fleet production cost per MWh $19.83 $19.50 $18.86 (a) Excludes Salem, which is operated by PSEG.
Refueling Outages in 2013
– Conducted 10 refueling outages – including Salem
– Average refueling outage duration – excluding Salem: 26 days
(At December 31, 2013) Location Owned Net 2013 Plant NSSS
Station Water Body Ownership Capacity (MW) Generation (GWh) Type Vendor
Braidwood Braidwood, IL 100% Exelon 2,353 19,662 PWR W 2 units Kankakee River
Byron Byron, IL 100% Exelon 2,319 19,547 PWR W 2 units Rock River
Calvert Cliffs Lusby, MD 50.01% Exelon 878 7,127 PWR CE 2 units Chesapeake Bay 49.99% EDF
Clinton Clinton, IL 100% Exelon 1,067 8,196 BWR GE 1 unit Clinton Lake
Dresden Morris, IL 100% Exelon 1,843 15,413 BWR GE 2 units Kankakee River
LaSalle Seneca, IL 100% Exelon 2,327 18,760 BWR GE 2 units Illinois River
Limerick Sanatoga, PA 100% Exelon 2,316 19,542 BWR GE 2 units Schuylkill River(g)
Nine Mile Point Scriba, NY 50.01% Exelon(j) 833 6,941 BWR GE 2 units Lake Erie 49.99% EDF(j)
Oyster Creek Forked River, NJ 100% Exelon 625 5,102 BWR GE 1 unit Barnegat Bay
Peach Bottom Delta, PA 50% Exelon 1,167 9,397 BWR GE 2 units Susquehanna River 50% PSEG Nuclear
Quad Cities Cordova, IL 75% Exelon 1,403 11,668 BWR GE 2 units Mississippi River 25% Mid-American Energy Holdings
R.E. Ginna Ontario, NY 50.01% Exelon 288 2,497 PWR W 1 unit Lake Erie 49.99% EDF
Salem Lower Alloways 2 units Creek Twp., NJ 42.6% Exelon 1,006 8,181 PWR W Deleware Estuary 57.4% PSEG Nuclear
Three Mile Island Middletown, PA 100% Exelon 837 6,659 PWR B&W 1 unit Susquehanna River
Total 19,262 158,692
Notes: Average in-service time = 31 years PWR = Pressurized Water Reactor; BWR = Boiling Water ReactorNSSS = Nuclear Steam Supply System; W = Westinghouse; CE = Combustion Engineering; GE = General Electric; B&W = Babcock & WilcoxAmounts 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.
(J) Reflects Exelon’s and EDF’s ownership interest in CENG. For Nine Mile Point, the coowner owns 18% of Unit 2. Thus Exelon’s and EDF’s ownership is 50.01% and 49.99%, respectively, of 82% of Nine Mile Point Unit 2.
35 Cooling Water Unit/ Annual Mean Start of Commercial Current License Last Refueling Spent Fuel Pool System(c) Ownership Rating (MW) Operations Expiration Completed Capacity Reached(f) Braidwood Closed 1/100% 1,192 1988 2026 Sept-13(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 Apr-13(d) in operation Calvert Cliffs Open 1/50.01% 446 1975 2034 Apr-12(e) ISFSI in operation 2/50.01% 432 1977 2036 Mar-13(e) Clinton Open 1/100% 1,067 1987 2026 Oct-13(e) 2015 Dresden Partial Open 2/100% 917 1970 2029 Dec-13(e) Dry Cask Storage 3/100% 873 1971 2031 Dec-12(e) in operation LaSalle Closed 1/100% 1,157 1984 2022 Feb-14(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-13(e) in operation Nine Mile Point Open/ 1/50.01% 308 1970 2029 May-13(e) Fuel pool not full; Closed 2/41.01% 524 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-13(e) in operation Quad Cities Open 1/75% 700 1973 2032 Apr-13(e) Dry Cask Storage 2/75% 703 1973 2032 Apr-12(e) in operation R.E. Ginna Open 1/50% 288 1970 2029 Nov-12(d) ISFSI in operation Salem Open 1/43% 504 1977 2036 May-13(d) Dry Cask Storage 2/43% 502 1981 2040 Nov-12(d) in operation Three Mile Island Closed 1/100% 837 1974 2034 Nov-13(e) 2023 19,200 Nuclear Operating Data(a) (continued)
2013 Net Generation (excluding Salem): 133,946 MWh
Planned Refueling Outages (including Salem)
2011: 12 actual 2014: 11 planned2012: 10 actual 2015: 11 planned2013: 10 actual 2016: 10 planned
CENG Nuclear Operating data
2013 2012 2011
Fleet capacity factor 95.0% 87.8% 93.4%
Refueling Outages in 2013
– Conducted 2 refueling outages
Planned Refueling Outages
2010: 2 actual 2013: 2 actual
2011: 3 actual 2014: 3 planned2012: 3 actual 2015: 3 planned 2016: 2 planned
Exelon Generation – Nuclear Generating Capacity
Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary
36
Owned generation as of December 31, 2013, unless otherwise noted. Table does not include station auxiliary equipment or plants comprised solely of peaking combustion turbines. 2013 data is presented for the full calendar year.
Net Generation Available for Sale (GWh)
Capacity(a) Fossil Station (Location) / Water Body (MW) 2013 2012 2011
Conemaugh (New Florence, PA) / Conemaugh River 531 3,678 3,324 3,382 Units: 2 coal units (baseload) Data reflects Exelon Generation’s 31.28% plant ownership.
Colorado Bend Energy Center (Wharton, TX) / Colorado River 498 1,739 1,644 1,524
Units: 4 2x1 CCGTs & 2 steam generators (intermediate)
Eddystone(b) (Eddystone, PA) / Delaware River 820 36 46 427
Units: 2 coal units (intermediate) – Retired, 2 oil/gas steam units (intermediate), 4 combustion turbines (peaking)
Fairless Hills (Falls Township, PA) / Delaware River(d) 60 240 247 242
Units: 2 landfill gas units (peaking)
Fore River (North Weymouth, MA) / Town River 726 3,818 4,048 4,781 Units: 4 2x1 CCGTs & 3 steam generators (intermediate)
Gould Street (Baltimore MD) / Patapsco River 97 19 40 21 Units: 1 gas steam unit (peaking)
Handley (Ft. Worth, TX) / Lake Arlington 1,265 343 858 585 Units: 3 gas steam units (2 peaking/1 intermediate)
Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary (continued)
37
Emissions (thousand tons) Reduction Technology Post Low NOx combustion burners with Induced Cooling SO2 NOx controls separated flue gas Water Type 2013 2012 2011 Scrubber (SCR or SNCR) overfire air recirculation System Conemaugh SO2 2.0 2.0 2.3 X NOx 5.7 5.1 5.5 2015 X CO2 3,624 3,368 3,349 Closed Colorado Bend SO2 * * * NOx 0.1 0.1 0.1 CO2 861 830 759 Closed Eddystone SO2 * 0.1 0.9 X NOx 0.1 0.1 0.8 (Coal Units) X X CO2 74 99 577 (Coal Units) (Coal Units) Open Fairless Hills SO2 0.1 0.1 0.1 NOx 0.1 0.1 0.1 CO2 346 353 208 Open Fore River SO2 * * * NOx 0.1 0.1 0.1 X CO2 1,640 1,733 2,018 Closed Gould Street SO2 * * * NOx * * * X CO2 13 29 17 Open Handley SO2 * * * NOx * 0.1 0.1 X CO2 251 601 422 Open
38 Owned generation as of December 31, 2013, unless otherwise noted. Table does not include station auxiliary equipment or plants comprised solely of peaking combustion turbines. 2013 data is presented for the full calendar year.
Net Generation Available for Sale (GWh)
Capacity(a) Fossil Station (Location) / Water Body (MW) 2013 2012 2011
Hillabee Energy Center (Alexander City, AL) / Municipal Supply 670 3,557 5,007 4,166
Units: 2 2x1 CCGTs & 1 steam generator (intermediate)
Keystone (Shelocta, PA) / Keystone Lake(f) 714 5,229 3,998 4,697 Units: 2 coal units (baseload) Data reflects Exelon Generation’s 41.98% plant ownership.
Mountain Creek (Dallas, TX) / Mountain Creek cooling pond 805 285 847 627 Units: 3 gas steam units (2 peaking/1 intermediate)
Mystic & Mystic Jet (Charlestown, MA) / Mystic River 2,002 7,054 8,627 9,324
Units: 4 2x1 CCGT, 3 steam generators
& 1 combustion turbine (intermediate)
Quail Run Energy Center (Odessa, TX) / Municipal 488 680 417 681
Units: 4 2x1 CCGT & 2 steam generators (intermediate)
Riverside (Baltimore, MD) / Patapsco River 228 21 27 20 Units: 1 gas steam unit & 3 gas/oil combustion turbines (peaking)
Schuylkill (Philadelphia, PA) / Schuylkill River 30 <1 <1 6
Units: 2 oil steam unit (peaking)
Wolf Hollow(e) (Granbury, TX) / Lake Granbury 705 2,936 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.
Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary (continued)
39 Exelon Generation – Fossil Emissions and Emission Reduction Technology Summary (continued)
Emissions (thousand tons) Reduction Technology Post Low NOx combustion burners with Induced Cooling SO2 NOx controls separated flue gas Water Type 2013 2012 2011 Scrubber (SCR or SNCR) overfire air recirculation System Hillabee Energy Ctr. SO2 * * * NOx 0.1 0.2 0.1 X CO2 1,520 2,123 1,786 Closed Keystone SO2 11.1 12.4 19.5 X NOx 7.0 7.3 8.7 X X CO2 5,195 4,121 4,766 Closed Mountain Creek SO2 * * * NOx 0.1 0.2 0.1 X X CO2 208 571 457 (Unit 8) (Units 6, 7) Open Mystic & Mystic Jet SO2 0.8 * * NOx 0.4 0.3 0.3 X X CO2 3,138 3,735 4,102 Closed Quail Run Energy Cnt. SO2 * * * NOx 0.1 0.1 0.1 X X CO2 385 245 398 Closed Riverside SO2 * * * NOx * * * CO2 16 21 20 Open SchuylkillSO2 * * * NOx * * * CO2 1 1 15 Open Wolf Hollow SO2 * * * NOx 0.3 0.4 0.1 X CO2 1,411 1,231 330 Closed *Indicates emissions less than 50 tons.
40 Exelon Generation – Total Contracted Generation Capacity
Contracted Generation (in MWs) as of December 31, 2013
2014 2015 2016
ERCOT 1,489 1,434 1,434
Oil/Gas 925 870 870 Renewables 564 564 564
Mid-Atlantic(a) 799 799 799
Oil/Gas 565 565 565
Renewables 234 234 234
Midwest 1,734 1,734 1,536
Oil/Gas 1,124 1,124 1,124 Renewables 610 610 412
NEPOOL 1,291 666 621
Oil/Gas 1,241 620 620
Renewables 50 46 1
South/West/Canada 4,113 3,493 2,031
Hydro 48 48 48
Oil/Gas 3,781 3,161 1,730
Renewables 284 284 253
Grand Total 9,427 8,127 6,421
(a) Excludes PPA with CENG
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