Annual Reports

  • 10-K (Feb 14, 2014)
  • 10-K (Feb 22, 2013)
  • 10-K (Feb 9, 2012)
  • 10-K (Feb 10, 2011)
  • 10-K (Feb 5, 2010)
  • 10-K (Feb 19, 2009)

 
Quarterly Reports

 
8-K

 
Other

Exelon 10-K 2011
Form 10-K
Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

 

FORM 10-K

 

 

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended December 31, 2010

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File

        Number

  

Exact Name of Registrant as Specified in its Charter;

State of Incorporation; Address of Principal

Executive Offices; and Telephone Number

   IRS Employer
Identification Number

1-16169

  

EXELON CORPORATION

(a Pennsylvania corporation)

10 South Dearborn Street

P.O. Box 805379

Chicago, Illinois 60680-5379

(312) 394-7398

   23-2990190

333-85496

  

EXELON GENERATION COMPANY, LLC

(a Pennsylvania limited liability company)

300 Exelon Way

Kennett Square, Pennsylvania 19348-2473

(610) 765-5959

   23-3064219

1-1839

  

COMMONWEALTH EDISON COMPANY

(an Illinois corporation)

440 South LaSalle Street

Chicago, Illinois 60605-1028

(312) 394-4321

   36-0938600

000-16844

  

PECO ENERGY COMPANY

(a Pennsylvania corporation)

P.O. Box 8699

2301 Market Street

Philadelphia, Pennsylvania 19101-8699

(215) 841-4000

   23-0970240

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

   Name of Each Exchange on
Which Registered
 

EXELON CORPORATION:

  

Common Stock, without par value

    
 
New York and
Chicago
  
  

PECO ENERGY COMPANY:

  

Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 Series, $4.30 Series and $3.80 Series

     New York   

Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company

     New York   

 

Securities registered pursuant to Section 12(g) of the Act:

 

COMMONWEALTH EDISON COMPANY:

Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants


Table of Contents

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

Exelon Corporation

  Yes   x   No   ¨

Exelon Generation Company, LLC

  Yes   x   No   ¨

Commonwealth Edison Company

  Yes   x   No   ¨

PECO Energy Company

  Yes   x   No   ¨

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 

Exelon Corporation

  Yes   ¨   No   x

Exelon Generation Company, LLC

  Yes   ¨   No   x

Commonwealth Edison Company

  Yes   ¨   No   x

PECO Energy Company

  Yes   ¨   No   x

 

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

     Large Accelerated    Accelerated    Non-Accelerated    Small Reporting
Company
 

Exelon Corporation

   ü         

Exelon Generation Company, LLC

         ü   

Commonwealth Edison Company

         ü   

PECO Energy Company

         ü   

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

 

Exelon Corporation

  Yes   ¨   No   x

Exelon Generation Company, LLC

  Yes   ¨   No   x

Commonwealth Edison Company

  Yes   ¨   No   x

PECO Energy Company

  Yes   ¨   No   x

 

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2010, was as follows:

 

Exelon Corporation Common Stock, without par value

   $ 25,082,540,918

Exelon Generation Company, LLC

   Not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

   No established market

PECO Energy Company Common Stock, without par value

   None

 

The number of shares outstanding of each registrant’s common stock as of January 31, 2011 was as follows:

 

Exelon Corporation Common Stock, without par value

   661,862,913

Exelon Generation Company, LLC

   not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

   127,016,519

PECO Energy Company Common Stock, without par value

   170,478,507

 

Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2011 Annual Meeting of

Shareholders are incorporated by reference in Part III.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

     Page No.  

GLOSSARY OF TERMS AND ABBREVIATIONS

     iv   

FILING FORMAT

     vii   

FORWARD-LOOKING STATEMENTS

     vii   

WHERE TO FIND MORE INFORMATION

     vii   

PART I

     

ITEM 1.

  

BUSINESS

     1   
  

General

     1   
  

Exelon Generation Company, LLC

     1   
  

Commonwealth Edison Company

     13   
  

PECO Energy Company

     15   
  

Employees

     19   
  

Environmental Regulation

     19   
  

Executive Officers of the Registrants

     25   

ITEM 1A.

  

RISK FACTORS

     30   

ITEM 1B.

  

UNRESOLVED STAFF COMMENTS

     50   

ITEM 2.

  

PROPERTIES

     50   
  

Exelon Generation Company, LLC

     50   
  

Commonwealth Edison Company

     52   
  

PECO Energy Company

     53   

ITEM 3.

  

LEGAL PROCEEDINGS

     54   
  

Exelon Corporation

     54   
  

Exelon Generation Company, LLC

     54   
  

Commonwealth Edison Company

     54   
  

PECO Energy Company

     54   

PART II

     

ITEM 5.

  

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     55   

ITEM 6.

  

SELECTED FINANCIAL DATA

     59   
  

Exelon Corporation

     59   
  

Exelon Generation Company, LLC

     60   
  

Commonwealth Edison Company

     61   
  

PECO Energy Company

     62   

ITEM 7.

  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

     63   
  

Exelon Corporation

     63   
  

General

     63   
  

Executive Overview

     63   
  

Critical Accounting Policies and Estimates

     75   
  

Results of Operations

     89   
  

Liquidity and Capital Resources

     116   
  

Exelon Generation Company, LLC

     144   
  

Commonwealth Edison Company

     146   
  

PECO Energy Company

     148   

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     133   
  

Exelon Corporation

     133   
  

Exelon Generation Company, LLC

     145   
  

Commonwealth Edison Company

     147   
  

PECO Energy Company

     149   

 

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     Page No.  

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     150   
  

Exelon Corporation

     158   
  

Exelon Generation Company, LLC

     163   
  

Commonwealth Edison Company

     168   
  

PECO Energy Company

     173   
  

Combined Notes to Consolidated Financial Statements

     178   
  

1. Significant Accounting Policies

     178   
  

2. Regulatory Matters

     192   
  

3. Acquisition

     207   
  

4. Accounts Receivable

     208   
  

5. Property, Plant and Equipment

     209   
  

6. Jointly Owned Electric Utility Plant

     213   
  

7. Intangible Assets

     213   
  

8. Fair Value of Financial Assets and Liabilities

     216   
  

9. Derivative Financial Instruments

     231   
  

10. Debt and Credit Agreements

     244   
  

11. Income Taxes

     251   
  

12. Asset Retirement Obligations

     260   
  

13. Retirement Benefits

     267   
  

14. Corporate Restructuring and Plant Retirements

     281   
  

15. Preferred Securities

     283   
  

16. Common Stock

     284   
  

17. Earnings Per Share and Equity

     291   
  

18. Commitments and Contingencies

     291   
  

19. Supplemental Financial Information

     309   
  

20. Segment Information

     319   
  

21. Related Party Transactions

     322   
  

22. Quarterly Data

     330   

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     332   

ITEM 9A.

  

CONTROLS AND PROCEDURES

     332   
  

Exelon Corporation

     332   
  

Exelon Generation Company, LLC

     332   
  

Commonwealth Edison Company

     332   
  

PECO Energy Company

     332   

ITEM 9B.

  

OTHER INFORMATION

     332   
  

Exelon Corporation

     332   
  

Exelon Generation Company, LLC

     332   
  

Commonwealth Edison Company

     332   
  

PECO Energy Company

     333   

PART III

     

ITEM 10.

  

DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

     334   
  

Exelon Corporation

     334   
  

Exelon Generation Company, LLC

     334   
  

Commonwealth Edison Company

     335   
  

PECO Energy Company

     337   

ITEM 11.

  

EXECUTIVE COMPENSATION

     340   

 

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Table of Contents
     Page No.  

ITEM 12.

  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

     402   
  

Exelon Corporation

     402   
  

Exelon Generation Company, LLC

     402   
  

Commonwealth Edison Company

     405   
  

PECO Energy Company

     402   

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

     406   

ITEM 14.

  

PRINCIPAL ACCOUNTING FEES AND SERVICES

     407   
  

Exelon Corporation

     407   
  

Exelon Generation Company, LLC

     408   
  

Commonwealth Edison Company

     408   
  

PECO Energy Company

     408   

PART IV

     

ITEM 15.

   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES      409   

SIGNATURES

     434   
  

Exelon Corporation

     434   
  

Exelon Generation Company, LLC

     435   
  

Commonwealth Edison Company

     436   
  

PECO Energy Company

     437   

CERTIFICATION EXHIBITS

  

 

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Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

 

Exelon Corporation and Related Entities

Exelon

   Exelon Corporation

Generation

   Exelon Generation Company, LLC

ComEd

   Commonwealth Edison Company

PECO

   PECO Energy Company

BSC

   Exelon Business Services Company, LLC

Exelon Corporate

   Exelon’s holding company

Exelon Transmission Company

   Exelon Transmission Company, LLC

Exelon Wind

   Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC

Enterprises

   Exelon Enterprises Company, LLC

Ventures

   Exelon Ventures Company, LLC

AmerGen

   AmerGen Energy Company, LLC

ComEd Funding

   ComEd Funding LLC

CTFT

   ComEd Transitional Funding Trust

PEC L.P.

   PECO Energy Capital, L.P.

PECO Trust III

   PECO Capital Trust III

PECO Trust IV

   PECO Energy Capital Trust IV

PETT

   PECO Energy Transition Trust

Registrants

   Exelon, Generation, ComEd, and PECO, collectively

Other Terms and Abbreviations

1998 restructuring settlement

   PECO’s 1998 settlement of its restructuring case mandated by the Competition Act

Act 129

   Pennsylvania Act 129 of 2008

AEC

   Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source

AEPS Act

   Pennsylvania Alternative Energy Portfolio Standards Act of 2004

AFUDC

   Allowance for Funds Used During Construction

ALJ

   Administrative Law Judge

AMI

   Advanced Metering Infrastructure

ARC

   Asset Retirement Cost

ARO

   Asset Retirement Obligation

ARP

   Title IV Acid Rain Program

ARRA of 2009

   American Recovery and Reinvestment Act of 2009

ASLB

   Atomic Safety Licensing Board

Block contracts

   Forward Purchase Energy Block Contracts

CAIR

   Clean Air Interstate Rule

CAMR

   Federal Clean Air Mercury Rule

CERCLA

   Comprehensive Environmental Response, Compensation and Liability Act of 1980

CFL

   Compact Fluorescent Light

Competition Act

   Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996

CPI

   Consumer Price Index

CTC

   Competitive Transition Charge

DOE

   United States Department of Energy

DOJ

   United States Department of Justice

DSP Program

   Default Service Provider Program

EE&C

   Energy Efficiency and Conservation/Demand

 

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Table of Contents

Other Terms and Abbreviations

EGS

   Electric Generation Supplier

EPA

   Environmental Protection Agency

ERCOT

   Electric Reliability Council of Texas

ERISA

   Employee Retirement Income Security Act, as amended

EROA

   Expected Rate of Return on Assets

ESPP

   Employee Stock Purchase Plan

FASB

   Financial Accounting Standards Board

FERC

   Federal Energy Regulatory Commission

FTC

   Federal Trade Commission

GAAP

   Generally Accepted Accounting Principles in the United States

GHG

   Greenhouse Gas

GSA

   Generation Supply Adjustment

GWh

   Gigawatt hour

HAP

   Hazardous air pollutants

HB 80

   Pennsylvania House Bill No. 80

Health Care Reform Acts

   Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010

IBEW

   International Brotherhood of Electrical Workers

ICC

   Illinois Commerce Commission

ICE

   Intercontinental Exchange

IFRS

   International Financial Reporting Standards

Illinois Act

   Illinois Electric Service Customer Choice and Rate Relief Law of 1997

Illinois EPA

   Illinois Environmental Protection Agency

Illinois Settlement Legislation

   Legislation enacted in 2007 affecting electric utilities in Illinois

IPA

   Illinois Power Agency

IRC

   Internal Revenue Code

IRS

   Internal Revenue Service

ISO

   Independent System Operator

ISO-NE

   ISO New England Inc.

kV

   Kilovolt

kW

   Kilowatt

kWh

   Kilowatt-hour

LIBOR

   London Interbank Offered Rate

LILO

   Lease-In, Lease-Out

LLRW

   Low-Level Radioactive Waste

LTIP

   Long-Term Incentive Plan

MGP

   Manufactured Gas Plant

MISO

   Midwest Independent Transmission System Operator, Inc.

Moody’s

   Moody’s Investor Service

mmcf

   Million Cubic Feet

MRV

   Market-Related Value

MW

   Megawatt

MWh

   Megawatt hour

NAAQS

   National Ambient Air Quality Standards

NAV

   Net Asset Value

NDT

   Nuclear Decommissioning Trust

NEIL

   Nuclear Electric Insurance Limited

NERC

   North American Electric Reliability Corporation

NJDEP

   New Jersey Department of Environmental Protection

 

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Table of Contents

Non-Regulatory Agreement Units

   Former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting

NOV

   Notice of Violation

NPDES

   National Pollutant Discharge Elimination System

NRC

   Nuclear Regulatory Commission

NWPA

   Nuclear Waste Policy Act of 1982

NYMEX

   New York Mercantile Exchange

OCI

   Other Comprehensive Income

OPEB

   Other Postretirement Employee Benefits

PA DEP

   Pennsylvania Department of Environmental Protection

PAPUC

   Pennsylvania Public Utility Commission

PGC

   Purchased Gas Cost Clause

PJM

   PJM Interconnection, LLC

POLR

   Provider of Last Resort

PPA

   Power Purchase Agreement

PCCA

   Pennsylvania Climate Change Act

PRP

   Potentially Responsible Parties

PSEG

   Public Service Enterprise Group Incorporated

PUHCA

   Public Utility Holding Company Act of 1935

PURTA

   Pennsylvania Public Realty Tax Act

RCRA

   Federal Resource Conservation and Recovery Act

REC

   Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

Regulatory Agreement Units

   Former ComEd and former PECO nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting

RFP

   Request for Proposal

Rider

   Reconcilable Surcharge Recovery Mechanism

RPM

   PJM Reliability Pricing Model

RPS

   Renewable Energy Portfolio Standards

RGGI

   Regional Greenhouse Gas Initiative

RMC

   Risk Management Committee

RTEP

   Regional Transmission Expansion Plan

RTO

   Regional Transmission Organization

S&P

   Standard & Poor’s Ratings Services

SEC

   United States Securities and Exchange Commission

SECA

   Seams Elimination Charge/Cost Adjustments/Assignment

SERP

   Supplemental Employee Retirement Plan

SFC

   Supplier Forward Contract

SGIG

   Smart Grid Investment Grant

SILO

   Sale-In, Lease-Out

SMP

   Smart Meter Program

SNF

   Spent Nuclear Fuel

SSCM

   Simplified Service Cost Method

Tax Relief Act of 2010

   Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010

TEG

   Termoelectrica del Golfo

TEP

   Termoelectrica Penoles

VIE

   Variable Interest Entity

 

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FILING FORMAT

 

This combined Form 10-K is being filed separately by Exelon, Generation, ComEd and PECO. Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

 

FORWARD-LOOKING STATEMENTS

 

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a Registrant include those factors discussed herein, including those factors with respect to such Registrant discussed in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, (c) ITEM 8. Financial Statements and Supplementary Data: Note 18 and (d) 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 Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

 

WHERE TO FIND MORE INFORMATION

 

The public may read and copy any reports or other information that a Registrant files with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC at www.sec.gov and Exelon’s website at www.exeloncorp.com. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

 

The Exelon corporate governance guidelines and the charters of the standing committees of its Board of Directors, together with the Exelon Code of Business Conduct and additional information regarding Exelon’s corporate governance, are available on Exelon’s website at www.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Bruce G. Wilson, Senior Vice President, Deputy General Counsel, and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

 

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Table of Contents

PART I

 

ITEM 1. BUSINESS

 

General

 

Exelon, a utility services holding company, operates through its principal subsidiaries—Generation, ComEd and PECO—as described below, each of which is treated as a reportable segment by Exelon. See Note 20 of the Combined Notes to Consolidated Financial Statements for additional segment information.

 

Exelon was incorporated in Pennsylvania in February 1999. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-7398.

 

Generation

 

Generation’s business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and its competitive retail supply operations. Generation has three reportable segments consisting of the Mid-Atlantic, Midwest, and South and West regions.

 

Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring, effective January 1, 2001, in which Exelon separated its generation and other competitive businesses from its regulated energy delivery businesses at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-5959.

 

ComEd

 

ComEd’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail customers in northern Illinois, including the City of Chicago.

 

ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was incorporated in 1907. ComEd’s principal executive offices are located at 440 South LaSalle Street, Chicago, Illinois 60605, and its telephone number is 312-394-4321.

 

PECO

 

PECO’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia.

 

PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103, and its telephone number is 215-841-4000.

 

Generation

 

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MW. Generation combines its large generation fleet with an

 

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experienced wholesale energy marketing operation and a competitive retail supply operation. Generation’s presence in well-developed wholesale energy markets, integrated hedging strategy that mitigates the adverse impact of short-term market volatility, and low-cost nuclear generating fleet, which is operated consistently at high capacity factors, position it well to succeed in competitive energy markets.

 

At December 31, 2010, Generation owned generation resources with an aggregate net capacity of 25,619 MW, including 17,047 MW of nuclear capacity. Generation controlled another 6,139 MW of capacity through long-term contracts.

 

Generation’s wholesale marketing unit, Power Team, draws upon Generation’s energy generation portfolio and logistical expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts and in spot markets.

 

Generation’s retail business provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Pennsylvania, Michigan and Ohio. Generation’s retail business is dependent upon continued deregulation of retail electric and gas markets and Generation’s ability to obtain supplies of electricity and gas at competitive prices in the wholesale market.

 

Generation is a public utility under the Federal Power Act, which gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including Generation, which is a public utility as FERC defines that term) and set cost-based rates should the FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and state environmental protection agencies. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC.

 

RTOs exist in a number of regions to provide transmission service across multiple transmission systems. To date, PJM, the MISO, ISO-NE and Southwest Power Pool, have been approved as RTOs. These entities are responsible for regional planning, managing transmission congestion, developing larger wholesale markets for energy and capacity, maintaining reliability, market monitoring and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems.

 

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Generating Resources

 

At December 31, 2010, the generating resources of Generation consisted of the following:

 

Type of Capacity

   MW  

Owned generation assets (a)

  

Nuclear

     17,047  

Fossil (b)

     6,189  

Hydroelectric/Renewable (c)

     2,383  
        

Owned generation assets

     25,619  

Long-term contracts (d)

     6,139  
        

Total generating resources

     31,758  
        

 

(a) See “Fuel” for sources of fuels used in electric generation.
(b) Includes 933 MW of capacity related to Units 1 and 2 at Cromby Generating Station and Units 1 and 2 at Eddystone Generating Station, which were approved for retirement by the Exelon Board of Directors on December 1, 2009. See Note 14 of the Combined Notes to Consolidated Financial Statements for further details.
(c) Includes Exelon Wind assets acquired on December 9, 2010. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details.
(d) Long-term contracts range in duration up to 21 years.

 

Generation has three reportable segments, the Mid-Atlantic, Midwest, and South and West, representing the different geographical areas in which Generation’s power marketing activities are conducted and where Generation’s owned and contracted generating resources are located. Mid-Atlantic represents Generation’s operations primarily in Pennsylvania, New Jersey and Maryland (approximately 36% of capacity); Midwest includes the operations in Illinois, Indiana, Michigan and Minnesota (approximately 46% of capacity); and the South and West includes operations primarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and Oregon (approximately 18% of capacity).

 

Nuclear Facilities

 

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with an aggregate of 17,047 MW of capacity. Generation wholly-owns all of its nuclear generating stations, except for Quad Cities Generating Station (75% ownership), Peach Bottom Generating Station (50% ownership) and Salem Generating Station (Salem) (42.59% ownership). Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2010 and 2009, electric supply (in GWh) generated from the nuclear generating facilities was 82% and 81%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of Generation’s electric supply sources.

 

AmerGen Reorganization. AmerGen, a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton Nuclear Power Station (Clinton), the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek) through that time. Effective January 8, 2009, AmerGen was merged into Generation, which now holds the operating licenses for Clinton, TMI and Oyster Creek.

 

Oyster Creek Station Shutdown. On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the closure of Oyster Creek.

 

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Nuclear Operations. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. As the largest generator of nuclear power in the United States, Generation can negotiate favorable terms for the materials and services that its business requires. Generation’s nuclear plants have historically benefited from minimal environmental impact from operations and a safe operating history.

 

During 2010 and 2009, the nuclear generating facilities operated by Generation achieved capacity factors of 93.9% and 93.6%, respectively. Generation aggressively manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s short and long-term supply commitments and Power Team marketing and trading activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe reliable operations.

 

In addition to the rigorous maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation has extensive safety systems in place to protect the plant, personnel and surrounding area in the unlikely event of an accident.

 

Regulation of Nuclear Power Generation. Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results, and communicates its assessment on a semi-annual basis. As of December 31, 2010, the NRC categorized each unit operated by Generation in the Licensee Response Column, which is the highest performance band. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures for nuclear generating facilities and/or increased operating costs of nuclear generating units.

 

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Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for Peach Bottom Units 2 and 3, Dresden Units 2 and 3, Quad Cities Units 1 and 2, Oyster Creek and Three Mile Island Unit 1. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

 

Station

   Unit      In-Service
Date (a)
     Current License
Expiration
 

Braidwood (b)

     1        1988        2026  
     2        1988        2027  

Byron (b)

     1        1985        2024  
     2        1987        2026  

Clinton (c)

     1        1987        2026  

Dresden (b)(e)

     2        1970        2029  
     3        1971        2031  

LaSalle (b)

     1        1984        2022  
     2        1984        2023  

Limerick (d)

     1        1986        2024  
     2        1990        2029  

Oyster Creek (d)(e)(f)

     1        1969        2029  

Peach Bottom (d)(e)

     2        1974        2033  
     3        1974        2034  

Quad Cities (b)(e)

     1        1973        2032  
     2        1973        2032  

Salem (d)

     1        1977        2016  
     2        1981        2020  

Three Mile Island (c)(e)

     1        1974        2034  

 

(a) Denotes year in which nuclear unit began commercial operations.
(b) Stations previously owned by ComEd.
(c) Stations previously owned by AmerGen.
(d) Stations previously owned by PECO.
(e) Stations for which the NRC has issued a renewed operating licenses for Dresden Unit 2 and Unit 3.
(f) On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

On May 29, 2009, a coalition of citizen groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the United States Court of Appeals for the Third Circuit. Oral argument was held before the Court on January 5, 2011. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.

 

On August 18, 2009, PSEG submitted an application to the NRC to extend the operating licenses of Salem Units 1 and 2 by 20 years. The NRC is expected to spend a total of 22 to 30 months to review the application before making a decision.

 

Generation expects to apply for and obtain approval of license renewals for the remaining nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the original license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual and assumed renewal of operating licenses for all of Generation’s operating nuclear generating stations.

 

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Nuclear Uprate Program. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.65 billion in overnight cost, as measured in 2010 dollars. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately 60% of the planned uprate MW, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remainder will come from additional projects across Generation’s nuclear fleet beginning in 2011 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the projects in light of changing market conditions. As part of this periodic review process, the uprate project at Three Mile Island is currently under evaluation. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards. The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may affect the timing and amount of the power increases associated with the power uprate initiative. Through December 31, 2010, Generation has added 101 MWs of nuclear generation through its uprate program, with another 98 MWs scheduled to be added in 2011.

 

New Site Development. Generation is keeping open the option of a new nuclear plant located in Victoria County in southeast Texas; however, Generation has not made a decision to build a nuclear plant at this time. In response to the overall downturn of the economy and the projection of sustained, low natural gas prices, Exelon revised its new nuclear plant development strategy. Exelon had previously submitted a Combined Construction and Operating License (COL) application to the NRC for the Victoria site. On March 25, 2010, Exelon submitted an application for an Early Site Permit (ESP) application for the site and subsequently withdrew its COL application. The ESP allows Exelon to establish the suitability of the Victoria site, which lessens the amount of work to do should it later decide to reapply for a COL. Additionally, the ESP accommodates a variety of possible future plant designs, allowing for flexibility in selecting a reactor technology later as part of a COL application. If approved by the NRC, the ESP would effectively reserve the site for 20 years with the possibility of renewal for another 20 years. Any decision to build at the Victoria County site would be made later based on then current economics. The Exelon board authorized a budget of $130 million for the Victoria County project, of which a total of $108 million had been expensed through December 31, 2010. The review and approval schedule published by the NRC estimates final issuance of the ESP in late 2014.

 

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities in on-site storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.

 

As of December 31, 2010, Generation had approximately 54,300 SNF assemblies (13,100 tons) stored on site in SNF pools or dry cask storage (this includes SNF at Zion Station, for which Generation retains ownership, see Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning). On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the end of the license renewal periods, and through

 

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decommissioning. The following table describes the current status of Generation’s SNF storage facilities.

 

Site

   Date for loss of full core reserve (a)  

Braidwood

     2012  

Byron

     Dry cask storage in operation   

Clinton

     2018  

Dresden

     Dry cask storage in operation   

LaSalle

     Dry cask storage in operation  

Limerick

     Dry cask storage in operation   

Oyster Creek

     Dry cask storage in operation   

Peach Bottom

     Dry cask storage in operation   

Quad Cities

     Dry cask storage in operation   

Salem

     Dry cask storage in operation   

Three Mile Island (b)

     2023  

 

(a) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to the closing of their on-site storage pools.
(b) The DOE previously has indicated it will begin accepting spent fuel in 2020. If this does not occur, Three Mile Island will need an onsite dry cask storage facility.

 

For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 18 of the Combined Notes to Consolidated Financial Statements.

 

As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site.

 

Generation is currently utilizing on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its Class A LLRW, which represent 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Oyster Creek and Salem), and Connecticut. Generation has pending license amendments for its Peach Bottom and LaSalle stations that will allow it to store LLRW from its remaining stations that have limited capacity. If approved, there will enough storage capacity to store all Class B and C LLRW for the life of all stations in Generations nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts and on-site storage.

 

Nuclear Insurance. Generation is subject to liability, property damage and other risks associated with a major accidental outage at any of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for details.

 

For information regarding property insurance, see ITEM 2. Properties—Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s financial condition and results of operations.

 

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Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Exelon Corporation, Executive Overview; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, Nuclear Decommissioning Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Notes 2, 8 and 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.

 

Dresden Unit 1 and Peach Bottom Unit 1 have ceased power generation. SNF at Dresden Unit 1 is currently being stored in dry cask storage until a permanent repository under the NWPA is completed. All SNF for Peach Bottom Unit 1, which ceased operation in 1974, has been removed from the site and the SNF pool is drained and decontaminated. Generation’s estimated liability to decommission Dresden Unit 1 and Peach Bottom Unit 1 was $182 million at December 31, 2010. As of December 31, 2010, NDT funds set aside to pay for these obligations were $330 million.

 

Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998.

 

On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements shall be deferred until such milestones are met. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning.

 

Fossil, Hydroelectric and Renewable Facilities

 

Generation operates various fossil, hydroelectric and renewable facilities and maintains ownership interests in several other facilities including LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2010 and 2009, electric supply (in GWh) generated from owned fossil, hydroelectric and renewable generating facilities was 6% of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.

 

John Deere Renewables. On December 9, 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power, for approximately $893 million in cash. Generation acquired 735 MWs of installed, operating wind capacity located in eight states. Approximately 75% of the operating portfolio’s expected output is already sold under long-term power purchase arrangements. Additionally, Generation will pay up to $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. This contingent consideration was valued at $32 million of which approximately $16 million has been recorded as a current liability and the remainder has been recorded as a noncurrent liability. As a result, total

 

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consideration recorded for the Exelon Wind acquisition was $925 million. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Exelon Wind acquisition.

 

Plant Retirements. On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. These actions were in response to the economic outlook related to the continued operation of these four units. Subsequently, PJM determined that transmission reliability upgrades will be necessary to alleviate reliability impacts and that those upgrades will be completed in a manner that will permit Generation’s retirement of the units on the following schedule: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011; Cromby Unit 2 on December 31, 2011; and Eddystone Unit 2 on June 1, 2012. These dates are dependent upon the completion of required transmission reliability upgrades and may be subject to further change. Generation revised the depreciable useful lives for the affected units to reflect the revised deactivation dates. For more information regarding plant retirements, see Note 14 of the Combined Notes to Consolidated Financial Statements.

 

Licenses. Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid. The license for the Conowingo Hydroelectric Project expires on August 31, 2014 and for the Muddy Run Pumped Storage Facility Project expires on September 1, 2014. In March 2009, Generation filed a Pre-Application Document and Notice of Intent to renew the licenses, pursuant to FERC relicensing requirements. For those plants located within the control areas administered by PJM or the New England control area administered by ISO-NE, notice is required to be provided to PJM or ISO-NE, as applicable, before a plant can be retired.

 

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. Generation maintains both property damage and liability insurance. For property damage and liability claims, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.

 

Long-Term Contracts

 

In addition to energy produced by owned generation assets, Generation sells electricity purchased under the following long-term contracts in effect as of December 31, 2010:

 

Seller

   Location      Expiration      Capacity (MW)  

Kincaid Generation, LLC

     Kincaid, Illinois         2013        1,108  

Tenaska Georgia Partners, LP (a)

     Franklin, Georgia         2030        945  

Tenaska Frontier, Ltd

     Shiro, Texas         2020        830  

Green Country Energy, LLC (b)

     Jenks, Oklahoma         2022        778  

Elwood Energy, LLC

     Elwood, Illinois         2012        775  

Lincoln Generating Facility, LLC

     Manhattan, Illinois         2011        664  

Wolf Hollow

     Granbury, Texas         2023        350  

Old Trail Windfarm, LLC

     McLean, Illinois         2026        198  

Others (c)

     Various         2011 to 2028         491  
              

Total

           6,139  
              

 

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(a) Generation has sold its rights to 945 MW of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a PPA with Georgia Power, a subsidiary of Southern Company for a 20 year period that began on June 1, 2010.
(b) Commencing June 1, 2012 and lasting for 10 years, Generation has agreed to sell its rights to 520 MW, or approximately two-thirds, of capacity, energy, and ancillary services supplied from its existing long-term contract with Green Country Energy, LLC through a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power Company, Inc..
(c) Includes long-term capacity contracts with seven counterparties.

 

Fuel

 

The following table shows sources of electric supply in GWh for 2010 and estimated for 2011:

 

     Source of Electric Supply  (a)  
         2010              2011 (Est.)      

Nuclear

     140,010        139,375  

Purchases—non-trading portfolio

     21,062        18,055  

Fossil, renewable and hydroelectric

     10,717        11,253  
                 

Total supply

     171,789        168,683  
                 

 

(a) Represents Generation’s proportionate share of the output of its generating plants.

 

The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its wholesale obligations, including to ComEd and PECO, and some of Generation’s retail business requirements.

 

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2015. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2015. All of Generation’s enrichment requirements have been contracted through 2012. Contracts for fuel fabrication have been obtained through 2013. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of its nuclear units.

 

Coal is procured primarily through annual supply contracts, with the remainder supplied through either short-term contracts or spot-market purchases.

 

Natural gas is procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or natural gas as fuel. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

 

Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates and Note 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

 

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Power Team

 

Generation’s wholesale marketing and retail electric supplier operations include the physical delivery and marketing of power obtained through its generation capacity and through long-term, intermediate-term and short-term contracts. Generation seeks to maintain a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. PPAs are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs as part of its overall strategic plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to customers and assisting customers to meet renewable portfolio standards. Generation may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be for more than the energy demanded by Power Team’s customers. Power Team then sells this open position, along with capacity not used to meet customer demand, in the wholesale electricity markets. Where necessary, Generation also purchases transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs in markets without an organized RTO. Generation also incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.

 

Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation also enters into transactions that are outside of this ratable sales plan, such as a financial swap with ComEd that is described below and runs into 2013. However, except for the ComEd swap arrangement, Generation is exposed to relatively greater commodity price risk beyond 2011 for which a larger portion of its electricity portfolio may be unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years. As of December 31, 2010, the percentage of expected generation hedged was 90%-93%, 67%-70%, and 32%-35% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts, including sales to ComEd and PECO to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts.

 

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At December 31, 2010, Generation’s short and long-term commitments relating to the purchase and sale of energy and capacity from and to unaffiliated utilities and others were as follows:

 

(in millions)

   Net Capacity
Purchases  (a)
     Power Only Purchases  (b)      Power Only
Sales
     Transmission Rights
Purchases (c)
 

2011

   $ 291      $ 60      $ 1,632      $ 9  

2012

     274        17        758        9  

2013

     151        —           314        6  

2014

     147        —           149        —     

2015

     141        —           150        —     

Thereafter

     940        —           670        —     
                                   

Total

   $ 1,944      $ 77      $ 3,673      $ 24  
                                   

 

(a) Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented as commitments represent Generation’s expected payments under these arrangements at December 31, 2010, including certain capacity charges which are subject to plant availability.
(b) Excludes renewable energy PPA contracts that are contingent in nature.
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

 

ComEd procures all of its electricity through a competitive procurement process, through which Generation supplies a portion of ComEd’s load. Additionally, in order to fulfill a requirement of the Illinois Settlement, Generation and ComEd entered into a five-year financial swap contract that expires on May 31, 2013. See ComEd—Retail Electric Services, Procurement Related Proceedings for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

 

Generation had a PPA with PECO under which Generation supplied PECO with all of PECO’s electric supply needs through December 31, 2010. Generation supplied electricity to PECO from its portfolio of generation assets, PPAs and other market sources. As of January 1, 2011, PECO procures all of its electricity through a competitive procurement process, through which Generation will continue to supply a portion of PECO’s load. See PECO—Retail Electric Services, Procurement Related Proceedings for additional information regarding PECO’s competitive, full-requirements energy-supply procurement process after 2010.

 

Capital Expenditures

 

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2011 are as follows:

 

(in millions)

      

Nuclear fuel (a)

   $ 1,025  

Production plant

     850  

Uprates

     475  

Wind

     225  
        

Total

   $ 2,575  
        

 

(a) Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant

 

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ComEd

 

ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to a diverse base of residential, commercial and industrial customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC related to distribution rates and service, the issuance of securities, and certain other aspects of ComEd’s business. ComEd is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business. Specific operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEd is subject to mandatory reliability standards set by the NERC.

 

ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of 9 million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of 3 million. ComEd has approximately 3.8 million customers.

 

ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2011 to 2066. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

 

ComEd’s kWh sales and peak electricity load are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on August 1, 2006 and was 23,613 MW; its highest peak load during a winter season occurred on January 15, 2009 and was 16,328 MW.

 

Retail Electric Services

 

Under Illinois law, transmission and distribution service is regulated, while electric customers are allowed to purchase generation from a competitive electric generation supplier.

 

At December 31, 2010, approximately 66,200 retail customers (primarily commercial and industrial customers), representing approximately 52% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier. There are currently a minimal number of residential customers being served by alternate suppliers. Customers who receive electricity from a competitive electric generation supplier continue to pay a delivery charge to ComEd. Under the current regulatory mechanisms in effect, ComEd is permitted to recover its electricity procurement costs from retail customers, without mark-up. Thus, although energy sales affect ComEd’s reported revenues, they do not affect its net income, as the energy sales are offset by equal amount of purchased power expense.

 

Under Illinois law, ComEd is required to deliver electricity to all customers. ComEd’s obligation to provide generation supply service, which is referred to as a POLR obligation, primarily varies by customer size. ComEd’s obligation to provide such service to residential customers and other small customers with demands of under 100 kW continues for all customers who do not or cannot choose a competitive electric generation supplier or who choose to return to the utility after taking service from a competitive electric generation supplier. ComEd does not have a fixed-price generation supply service obligation to most of its largest customers with demands of 100 kW or greater, as this group of customers has previously been declared competitive. Beginning June 2010 ComEd had no fixed price generation supply service obligations for customers with demands of 100-400 kW. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

 

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Procurement Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement, ComEd hedged the price of a significant portion of energy purchased on the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. See Notes 2 and 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

 

Electric Distribution Rate Cases. The ICC issued an order in ComEd’s 2007 electric distribution rate case approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). On November 18, 2010, the Court denied ComEd’s petition for rehearing in connection with the September 30, 2010 ruling. On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court. Subsequent to the Illinois Appellate Court’s ruling, ComEd filed a request with the ICC to allow it to request recovery, through inclusion in the 2010 Rate Case, of $3 million in operation and maintenance costs, as well as carrying costs associated with capital investment in the ICC-approved AMI/Customer Applications pilot program. The AMI pilot program capital investment had already been requested in rate base in the 2010 Rate Case. On December 2, 2010, the ICC approved ComEd’s request. The investment and the pilot program costs are subject to challenge in the 2010 Rate Case proceeding.

 

On June 30, 2010, ComEd requested ICC approval for an increase of $396 million, subsequently changed to $326 million, to its annual delivery services revenue requirement (2010 Rate Case) to allow ComEd to continue modernizing its electric delivery system and recover the costs of substantial investments made since its last rate filing in 2007. The requested rate increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case makes it highly unlikely that the ICC would decide the post-test year accumulated depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $326 million could be reduced by approximately $85 million as a result of this adjustment. Certain parties have submitted testimony recommending significant reductions to ComEd’s requested increase as well as the write-off of certain assets, most notably the regulatory asset associated with severance costs, which was approximately $74 million as of December 31, 2010. Management believes the regulatory asset is appropriate based on the ICC’s orders in ComEd’s last two rate cases. The new electric distribution rates are expected to take effect no later than June 2011. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s rate case proceedings.

 

Other. Illinois law provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the

 

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utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. ComEd does not believe that during the years 2010, 2009 and 2008 it had any interruptions that have triggered this damage liability or reimbursement requirement.

 

Construction Budget

 

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities, to ensure the adequate capacity and reliability of its system. Based on PJM’s RTEP, ComEd has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2011 is $1,015 million which includes RTEP projects. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further information.

 

PECO

 

PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the PAPUC as to electric and gas distribution rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is a public utility under the Federal Power Act subject to regulation by FERC as to transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation as to pipeline safety and other aspects of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to NERC mandatory reliability standards.

 

PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 1,900 square miles, with a population of approximately 3.8 million, including approximately 1.5 million in the City of Philadelphia. PECO supplies natural gas service in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.6 million customers and natural gas to approximately 490,000 customers.

 

PECO has the necessary authorizations to deliver regulated electric and natural gas service in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PAPUC and/or “grandfathered rights,” which are rights generally unlimited as to time and generally exclusive from competition from other electric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of another natural gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

 

PECO’s kWh sales and peak electricity load are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating. PECO’s highest peak load occurred on August 3, 2006 and was 8,932 MW; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MW.

 

PECO’s natural gas sales are generally higher during the winter months when cold temperatures create demand for winter heating. PECO’s highest daily natural gas send out occurred on January 17, 2000 and was 718 mmcf.

 

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Retail Electric Services

 

PECO’s retail electric sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. Under the 1998 restructuring settlement, PECO’s electric generation rates were capped through a transition period which ended on December 31, 2010. During the transition period, PECO was authorized to recover from customers $5.3 billion of costs that might not have otherwise been recovered in a competitive market (stranded costs) with a 10.75% return on the unamortized balance through the imposition and collection of a non-bypassable CTC, which was a component of the capped electric generation rate on customer bills. At December 31, 2010, PECO’s stranded costs were fully recovered.

 

Beginning January 1, 2011, PECO’s electric supply procurement cost rates charged to default service customers are subject to quarterly adjustments designed to recover or refund the difference between PECO’s actual cost of electricity delivered and the amount included in rates without markup through the GSA.

 

Pennsylvania permits competition by EGSs for the supply of retail electricity while transmission and distribution service remains regulated under the Competition Act. For the year ended December 31, 2010, less than 1% of PECO’s residential and large commercial and industrial and 4% of its small commercial and industrial loads were purchased from alternative EGSs. The small percentage of customer load provided by an alternative EGS is due to the electric generation rate caps that were lower than current market prices throughout the transition period. Customers that choose an alternative EGS are not subject to PECO’s electric supply procurement cost rates. In preparation for the transition to market-based competitive pricing, multiple alternative EGSs began marketing to customers in PECO’s service territory. As of January 31, 2011, PECO believes that at least 10% of residential, 46% of small commercial and industrial and 86% of large commercial and industrial loads will be purchased from alternative EGSs. Beginning with January 2011 customer bills, PECO presented its electric supply Price to Compare, which will be updated quarterly, to assist customers with the evaluation of offers from alternative EGSs. PECO’s average residential Price to Compare for the first three months of 2011 is 9.92 cents per kWh.

 

Customer selection of an alternative EGS or PECO as default service provider does not impact PECO’s results of operations or financial position. PECO’s cost of electric supply is passed directly through to default service customers without markup. For those customers that choose an alternative EGS, PECO will act as the billing agent but will not record revenues or expenses related to this electric supply. PECO remains the distribution service provider for all the customers in its service territory and charges a regulated rate for delivery service. PECO receives transmission revenue from PJM for customers that select an alternative EGS.

 

Procurement Proceedings. Prior to January 1, 2011, PECO procured all its electric supply under a full requirements PPA with Generation, which expired on December 31, 2010. The term and procurement costs under the PPA with Generation corresponded with PECO’s transition period and capped electric generation rates in accordance with its 1998 restructuring settlement. Beginning January 1, 2011, PECO’s electric supply for its customers is procured through a competitive process in accordance with its PAPUC-approved DSP Program. During 2010, PECO entered into contracts with PAPUC-approved bidders for its third and fourth competitive procurements of electric supply for default electric service commencing January 2011, which included fixed price full requirement contracts for all procurement classes, spot market price full requirements contracts for the commercial and industrial procurement classes, and block energy contracts for the residential procurement class. As of December 31, 2010, including the previous competitive procurements completed in 2009 and 2010, the 2011 expected electric supply for all customer classes had been substantially procured. PECO will conduct five additional competitive procurements for electric supply for all customer classes during the term of its DSP Program.

 

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Electric Distribution Rate Case. In December 2010, the PAPUC approved a settlement of PECO’s electric distribution rate case filed in August 2010 that provides for an annual revenue increase of $225 million. The approved electric distribution rates became effective on January 1, 2011. The electric distribution rate case settlement and the electric supply procurement results indicate an increase of 5.1% in the average residential customer total electric bill in January 2011, above 2010 bills.

 

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Smart Meter and Energy Efficiency Programs

 

Smart Meter Programs. In April 2010, the PAPUC approved PECO’s $550 million Smart Meter Procurement and Installation Plan, which was filed in accordance with the requirements of Act 129. PECO filed for PAPUC approval of an initial dynamic pricing and customer acceptance program in October 2010, and plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.

 

Also, in April 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project—Smart Future Greater Philadelphia. As a result of the SGIG funding, PECO will deploy 600,000 smart meters within three years, accelerate universal deployment of more than 1.6 million smart meters from 15 years to 10 years and increase smart grid investments to approximately $100 million over the next three years. In total, over the next 10 years, PECO is planning to spend up to $650 million on its smart grid and smart meter infrastructure. The SGIG funding will be used to significantly reduce the impact of those investments on PECO customers.

 

Energy Efficiency Programs. In February 2010, the PAPUC approved PECO’s EE&C plan, which was filed pursuant to Act 129’s EE&C reduction targets. The approved four-year plan totals more than $330 million and includes a CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. In September 2010, PECO filed revisions to the EE&C Plan previously approved in February 2010 that included adjustments to certain incentive levels and the addition of energy efficiency measures to the existing portfolio. These revisions do not impact the total spending or timely recovery under the approved EE&C plan. On January 27, 2011, the PAPUC unanimously approved PECO’s EE&C Plan revisions.

 

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Natural Gas

 

PECO’s natural gas sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a portion of total rates, are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates without markup through the PGC.

 

PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. In 2010, 39% of PECO’s current total yearly throughput was provided by natural gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial and industrial customers. Natural gas distribution service provided to customers by

 

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PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services at regulated rates.

 

Procurement Proceedings. PECO’s natural gas supply is provided through purchases from a number of suppliers. These purchases are primarily delivered under long-term firm transportation contracts for terms of up to two years. PECO’s aggregate annual firm supply under these firm transportation contracts is 46 million dekatherms. Peak natural gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 23 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 30% of PECO’s 2010-2011 heating season planned supplies.

 

Natural Gas Distribution Rate Cases. On January 1, 2009, PECO implemented the natural gas distribution rates approved by the PAPUC in its settlement of the 2008 natural gas distribution rate case that provided for an additional $77 million of revenue annually. In December 2010, the PAPUC approved a settlement of PECO’s natural gas distribution rate case filed in August 2010 that provides an increase in annual revenue of $20 million. The approved natural gas distribution rates became effective on January 1, 2011.

 

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Construction Budget

 

PECO’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities to ensure the adequate capacity, reliability and efficiency of its system. Based on PJM’s RTEP, PECO has various construction commitments, including costs related to transmission system reliability upgrades due to Generation’s plant retirements, as discussed in Notes 14 and 18 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2011 is $450 million, which includes capital expenditures related to the smart meter program and SGIG project net of DOE expected reimbursements.

 

ComEd and PECO

 

Transmission Services

 

ComEd and PECO provide unbundled transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under FERC’s open access transmission policy promulgated in Order No. 888, ComEd and PECO, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. ComEd and PECO are required to comply with FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s employees and wholesale merchant employees.

 

PJM is the ISO and the FERC-approved RTO for the Mid-Atlantic and Midwest regions. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the PJM region. ComEd and PECO are members of PJM and provide regional transmission service pursuant to the PJM Tariff. ComEd, PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM, and their transmission systems are currently under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.

 

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ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.

 

As a result of PECO’s 1998 restructuring settlement, retail transmission rates were capped at the level in effect on December 31, 1996, which remained unchanged through December 31, 2010. PECO’s transmission rate included in the PJM Open Access Transmission Tariff is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for transmission service. PECO’s 2010 electric distribution rate case settlement provided for recovery of PJM transmission network service charges and RTEP charges from default service customers, on a full and current basis through a rider.

 

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information regarding transmission services.

 

Employees

 

As of December 31, 2010, Exelon and its subsidiaries had 19,214 employees in the following companies, of which 8,550 or 44% were covered by collective bargaining agreements (CBAs):

 

     IBEW Local 15  (a)      IBEW Local 614  (b)      Other CBA
agreements (c)
     Total Employees
Covered by CBA
     Total
Employees
 

Generation

     1,684        199        1,801        3,684        9,595  

ComEd

     3,495        —           —           3,495        5,692  

PECO

     —           1,258        —           1,258        2,423  

Other (d)

     86        —           27        113        1,504  
                                            

Total

     5,265        1,457        1,828        8,550        19,214  
                                            

 

(a) A separate CBA between ComEd and IBEW Local 15, ratified on November 20, 2009, covers approximately 36 employees in ComEd’s System Services Group.
(b) 1,258 PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614. The CBAs expire on March 31, 2015. Additionally, Exelon Power, an operating unit of Generation, has an agreement with IBEW Local 614, which expires on March 31, 2015 and covers 199 employees.
(c) During 2009 and early 2010, CBAs were agreed to with the following Security Officers unions: Braidwood, Byron, Clinton, Dresden, Oyster Creek and TMI. The agreements generally expire during 2012 except for the agreements at Clinton and Oyster Creek, which expire in 2013. Additionally, during 2009, a 5-year agreement was reached with Oyster Creek Nuclear Local 1289, which will expire in 2015. Also in 2010, a 3-year agreement was negotiated with New England ENEH, UWUA Local 369, which will expire in 2014, and covers 10 employees.
(d) Other includes shared services employees at BSC.

 

Environmental Regulation

 

General

 

Exelon, Generation, ComEd and PECO are subject to environmental regulation administered by the U.S. EPA and various state and local environmental protection agencies or boards. State and local regulation includes the authority to regulate air, water and noise emissions and solid waste disposals. The Registrants are also subject to legislation regarding environmental matters by the United States Congress and by various state and local jurisdictions where the Registrants operate their facilities.

 

The Exelon board of directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental matters, including the CEO who also serves as Exelon’s Chief Environmental Officer; the Vice President, Corporate Strategy and

 

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Exelon 2020; the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation, ComEd and PECO. Performance for those individuals directly involved in environmental strategy activities is reviewed and affects compensation as part of the annual individual performance review process. The Exelon board has delegated to its corporate governance committee authority to oversee Exelon’s strategies and efforts to protect and improve the quality of the environment, including, but not limited to, Exelon’s climate change and sustainability policies and programs, and Exelon 2020, Exelon’s comprehensive business and environmental plan, as discussed in further detail below. The Exelon board has also delegated to its generation oversight committee authority to oversee environmental, health and safety issues relating to Generation, and to its energy delivery oversight committee authority to oversee environmental, health and safety issues related to ComEd, PECO and Exelon Transmission Company.

 

Water

 

Under the Federal Clean Water Act (Clean Water Act), NPDES permits for discharges into waterways are required to be obtained from the U.S. EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. All of Generation’s power generation facilities discharge industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension.

 

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the impact to Exelon of state permitting agencies’ administration of the Phase II rule implementing Section 316(b) of the Clean Water Act, as well as the planned cessation of generation operations at Oyster Creek.

 

Generation is also subject to the jurisdiction of certain other state and regional agencies and compacts, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.

 

Solid and Hazardous Waste

 

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the U.S. EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. Government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the U.S. EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with a U.S. EPA-directed cleanup, may voluntarily settle with the U.S. Government concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Illinois and Pennsylvania, have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, the RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.

 

Generation, ComEd and PECO and their subsidiaries are or are likely to become parties to proceedings initiated by the U.S. EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party.

 

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Environmental Remediation

 

ComEd and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to the 1950s. ComEd and PECO generally did not operate MGPs as corporate entities but did acquire MGP sites as part of the absorption of smaller utilities, for which they may be liable for environmental remediation. ComEd, pursuant to an ICC order, and PECO, pursuant to the joint settlements of the 2008 and 2010 natural gas distribution rate cases, are recovering environmental remediation costs of the MGP sites through a provision within customer rates. PECO’s 2010 natural gas distribution rate case increased the annual MGP recovery to be collected from customers beginning in January 2011.

 

The amount to be expended in 2011 at Exelon for compliance with environmental remediation is expected to total $23 million, consisting of $17 million and $6 million at ComEd and PECO, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

 

See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ results of operations, cash flows and financial position.

 

Air

 

Air quality regulations promulgated by the U.S. EPA and the various state and local environmental agencies in Illinois, Massachusetts, Pennsylvania and Texas in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx), mercury and other pollutants and require permits for operation of emissions sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically. The Amendments establish a comprehensive and complex national program to substantially reduce air pollution, including a two-phase program to reduce acid rain effects by significantly reducing emissions of SO2 and NOx from power plants. Flue-gas desulfurization systems (SO2 scrubbers) have been installed at all of Generation’s coal-fired units.

 

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding clean air regulation and legislation in the forms of the proposed Transport Rule, the regulation of hazardous air pollutants from fossil generating stations, and regulation of GHG emissions, in addition to NOVs issued to Generation and ComEd for alleged violations of the Clean Air Act.

 

Global Climate Change

 

Exelon believes the evidence of global climate change is compelling and that the energy industry, though not alone, is a significant contributor to the human-caused emissions of GHGs that many in the scientific community believe contribute to global climate change, as reported by the National Academy of Sciences in May 2010. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, wind and hydroelectric), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions, primarily at its fossil fuel-fired generating plants; CO2, methane and nitrous oxide are all emitted in this process, with CO2 representing the largest portion of these GHG emissions. GHG emissions from Generation’s combustion of fossil fuels represent approximately 90% of Exelon’s total GHG emissions. However, only approximately 6% of Exelon’s total electric supply is provided by its fossil fuel generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the gas pipeline system and the coal piles at its generating plants,

 

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sulfur hexafluoride (SF6) leakage in its electric operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity in its facilities. Despite its small carbon footprint, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions. See Item 1A. Risk Factors for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.

 

Climate Change Regulation. Exelon is, or may become, subject to climate change regulation or legislation at the international, Federal, regional and state levels.

 

International Climate Change Regulation. At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The Conference of the Parties met in Mexico in December 2010 and while some progress was made in the Cancun Agreement, the fundamental issues around GHG emission reductions and a successor to the Kyoto Protocol remain unresolved. The next Conference of the Parties meeting will be held in December 2011 in South Africa.

 

Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

 

Numerous bills were introduced in Congress during the 111th Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards, but none were passed by both houses of Congress. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable. In reaction to the U.S. EPA’s proposed regulation of GHG emissions, various bills have been introduced in the U.S. House of Representatives that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.

 

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal

 

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legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

 

Regional and State Climate Change Legislation and Regulation. At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) signed the Midwestern Greenhouse Gas Accord. Under that Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In May 2010, an advisory group appointed by the Governors issued recommendations, but no actions have been taken on the recommendations.

 

At the state level, the PCCA was signed into law in Pennsylvania in July 2008. The PCCA requires, among other things, that: a Climate Change Advisory Committee be formed; a report on the potential impact of climate change in Pennsylvania be developed; the PA DEP develop a GHG inventory for Pennsylvania; a voluntary GHG registry be identified; and the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan for consideration by the Pennsylvania legislature on October 9, 2009.

 

Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change, nuclear power as well as other virtually non-GHG emitting power will play a pivotal role. As a result, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon believes that the significance of its low GHG emission profile can only grow as policymakers take action to address global climate change.

 

Despite Exelon’s low GHG emission inventory and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon made a voluntary commitment in 2005 under the U.S. EPA’s Climate Leaders Program to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. Exelon achieved this goal by reducing its carbon dioxide-equivalent (CO2e) emissions to 9.7 million metric tons in 2008, from a 2001 baseline of 15.7 million metric tons. This was accomplished through the retirement of older, inefficient fossil power plants, reduced leakage of SF6, increased use of renewable energy and energy efficiency initiatives.

 

In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and those of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels).

 

Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. In 2010, Exelon announced that it had achieved just over 50% of the annual Exelon 2020 goal. The planned retirement of fossil units, Cromby Units 1 and 2 and Eddystone Unit 1 in 2011 and Eddystone Unit 2 in 2012, will further contribute to fully achieving the goal. The early retirement of Oyster Creek may result in increased generation from fossil generating plants in the PJM RTO, which could result in increased GHG emissions under Exelon 2020 through reverse displacement. The current plan for achieving the Exelon 2020 goal accounts for these events.

 

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Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s Smart Ideas portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs at PECO to meet the requirements of Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding ComEd and PECO smart grid filings and stimulus grant awards. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power and adding capacity to existing nuclear plants through uprates.

 

Exelon has incorporated Exelon 2020 into its overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. Specific initiatives and the amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards. As further legislation and regulation imposing requirements on emissions of air pollutants are promulgated, Exelon’s emissions reduction efforts will position the company to benefit from the long-term positive impact of the requirements on capacity and energy prices while minimizing the impact of costs of compliance on Exelon’s operations, cash flows or financial position.

 

The Exelon 2020 strategy is reviewed annually and updated to reflect changes in the market, regulations, technology and other factors that affect the merit of various GHG abatement options. In spite of the recent economic downturn, the decline in wholesale power prices and the uncertainty of Federal climate policy, Exelon 2020 has been demonstrated to be a sustainable business strategy.

 

Renewable and Alternative Energy Portfolio Standards

 

Thirty-three states have adopted some form of RPS requirement. As previously described, Illinois and Pennsylvania have laws specifically addressing energy efficiency and renewable energy initiatives. In addition to state level activity, RPS legislation has been considered and may be considered again in the future by the United States Congress. Also, states that currently do not have RPS requirements may determine to adopt such legislation in the future.

 

The Illinois Settlement Legislation required that procurement plans implemented by electric utilities include cost-effective renewable energy resources or approved equivalents such as RECs in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers by June 1, 2008, increasing to 10% by June 1, 2015, with a goal of 25% by June 1, 2025. Utilities are allowed to pass-through any costs from the procurement of these renewable resources or approved equivalents subject to legislated rate impact criteria. As of December 31, 2010, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. See Note 2 and Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The AEPS Act is effective for PECO beginning in 2011, following the expiration of PECO’s transition period. During 2011, PECO will be required to supply approximately 3.5% and 6.2% of electric energy generated from Tier I (including solar, wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within Pennsylvania) and Tier II (including waste coal, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification

 

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technology) alternative energy resources, respectively, as measured in AECs. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for Tier II by 2021. In order to prepare for the first year of required compliance, PECO procured and banked AECs in accordance with their PAPUC-approved plan over the past three years. PECO has entered into five-year agreements and ten-year agreements with accepted bidders, including Generation, to purchase annually 452,000 non-solar and 8,000 solar Tier 1 AECs, respectively. PECO also purchases AECs through its DSP Program full requirement contracts. In November 2010, PECO filed a petition with the PAPUC for approval to procure Tier II AECs to satisfy PECO’s compliance requirements for the AEPS reporting years ending 2011 and 2012.

 

Similar to ComEd and PECO, Generation’s retail electric business must source a portion of the electric load it serves in IL and PA from renewable resources or approved equivalents such as RECs. While Generation is not directly affected by RPS or AEPS legislation from a compliance perspective, potential regulation and legislation regarding renewable and alternative energy resources could increase the pace of development of wind and other renewable/alternative energy resources, which could put downward pressure on wholesale market prices for electricity in some markets where Exelon operates generation assets. At the same time, such developments may present some opportunities for sales of Generation’s renewable power, including from Exelon Wind, Generation’s hydroelectric and landfill gas generating stations and wind energy PPAs.

 

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Executive Officers of the Registrants as of February 10, 2011

 

Name

   Age   

Position

  

Period

Rowe, John W.

   65    Chairman, Chief Executive Officer and Director, Exelon    2000 - Present
      Chairman, Generation    2008 - Present
      Chairman, PECO    2007 - Present
      President, Exelon    2004 - 2008
      President, Generation    2007 - 2008
      Director, ComEd    2009 - Present
      Director, PECO    2005 - Present

Crane, Christopher M.

   52    President and Chief Operating Officer, Exelon; President, Generation    2008 - Present
      Chief Operating Officer, Generation    2007 - 2010
      Executive Vice President, Exelon    2007 - 2008
      President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon    2004 - 2007

Clark, Frank M.

   65    Chairman and Chief Executive Officer, ComEd    2005 - Present
      Director, ComEd    2002 - Present

O’Brien, Denis P.

   50    Chief Executive Officer, PECO; Executive Vice President, Exelon    2007 - Present
      President and Director, PECO    2003 - Present

Gillis, Ruth Ann M.

   56    President, Exelon Business Services Company    2005 - Present
      Executive Vice President, Exelon    2008 - Present
      Chief Administrative and Diversity Officer, Exelon    2010 - Present
      Chief Diversity Officer, Exelon    2009 - 2010
      Senior Vice President, Exelon    2002 - 2008

 

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Name

   Age   

Position

  

Period

Von Hoene Jr., William A.

   57    Executive Vice President, Finance and Legal, Exelon   

2009 - Present

      Executive Vice President and General Counsel, Exelon   

2008 - 2009

      Senior Vice President, Exelon Business Services Company   

2004 - 2009

      Senior Vice President, Exelon   

2006 - 2008

Hilzinger, Matthew F.

   47    Senior Vice President and Chief Financial Officer, Exelon; Chief Financial Officer, Generation   

2008 - Present

      Treasurer, Exelon & Generation   

2011 - Present

      Senior Vice President and Corporate Controller, Exelon   

2005 - 2008

      Principal Accounting Officer, ComEd; Principal Accounting Officer, PECO   

2005 - 2006

      Vice President, ComEd   

2004 - 2006

Cornew, Kenneth W.

   45    Senior Vice President, Exelon; President, Power Team   

2008 - Present

      Senior Vice President, Trading and Origination, Power Team   

2007 - 2008

      Senior Vice President, Power Transactions, Power Team   

2003 - 2006

Dominguez, Joseph

   47    Senior Vice President, Federal Regulatory Affairs & Public Policy, Exelon   

2010 - Present

      Senior Vice President, State Governmental Affairs, Generation   

2010 - Present

      Senior Vice President, State Regulatory Affairs and General Counsel, Generation   

2010 - 2010

      Senior Vice President, Communications and Public Affairs, Exelon   

2009 - 2010

      Senior Vice President, Exelon Business Services Company; Senior Vice President, Generation   

2007 - 2010

      Vice President and Associate General Counsel, Exelon Business Services Company   

2004 - 2007

Pramaggiore, Anne R.

   52    President and Chief Operating Officer, ComEd   

2009 - Present

      Executive Vice President, Customer Operations, Regulatory and External Affairs, ComEd   

2007 - 2009

      Senior Vice President, Regulatory and External Affairs, ComEd   

2005 - 2007

Bradford, Darryl M.

   55    Senior Vice President and General Counsel, Exelon   

2010 - Present

      General Counsel, ComEd   

2007 - 2010

      Senior Vice President, Regulatory and Energy Policy, ComEd   

2009 - 2010

      Senior Vice President, ComEd   

2007 - 2009

      Vice President, ComEd   

2005 - 2006

 

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Name

   Age   

Position

  

Period

DesParte, Duane M.

   47    Vice President and Corporate Controller, Exelon   

2008 - Present

      Vice President, Finance, Exelon Business Services Company   

2007 - 2008

      Vice President, Business Operations, ComEd; Vice President, Business Operations, PECO   

2004 - 2006

 

Generation

 

Name

   Age   

Position

  

Period

Rowe, John W.

   65    Chairman, Generation   

2008 - Present

      Chairman, Chief Executive Officer and Director, Exelon   

2000 - Present

      Chairman, PECO   

2007 - Present

      President, Generation   

2007 - 2008

      President, Exelon   

2004 - 2008

      Director, ComEd   

2009 - Present

      Director, PECO   

2005 - Present

Crane, Christopher M.

   52    President and Chief Operating Officer, Exelon; President, Generation   

2008 - Present

      Chief Operating Officer, Generation   

2007 - 2010

      Executive Vice President, Exelon   

2007 - 2008

      President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon   

2004 - 2007

Pardee, Charles G.

   51    Senior Vice President and Chief Operating Officer, Generation   

2010 - Present

      President, Exelon Nuclear   

2008 -2010

      Chief Nuclear Officer, Generation   

2007 - 2010

      Senior Vice President, Generation   

2007 - 2008

      Chief Operating Officer, Generation   

2005 - 2007

Cornew, Kenneth W.

   45    Senior Vice President, Exelon; President, Power Team   

2008 - Present

      Senior Vice President, Trading and Origination, Power Team   

2007 - 2008

      Senior Vice President, Power Transactions, Power Team   

2003 - 2006

Pacilio, Michael J.

   50    President, Exelon Nuclear and Chief Nuclear Officer, Generation   

2010 - Present

      Chief Operating Officer, Exelon Nuclear   

2007 - 2010

      Senior Vice President, Mid-West PWR Operations, Exelon Nuclear   

2005 - 2007

Garg, Sunil

   44    Senior Vice President, Generation; President, Exelon Power   

2010 - Present

      Senior Vice President, Human Resources, Exelon; Senior Vice President, Exelon Business Services Company   

2009 - 2010

      Vice President, Exelon Business Services Company   

2007 - 2009

      Director of Integrated Business Services, Exelon Business Services Company   

2004 - 2007

 

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Name

   Age     

Position

  

Period

Dominguez, Joseph

     47      Senior Vice President, State Governmental Affairs, Generation   

2010 - Present

      Senior Vice President, Federal Regulatory Affairs & Public Policy, Exelon   

2010 - Present

      Senior Vice President, State Regulatory Affairs and General Counsel, Generation   

2010 - 2010

      Senior Vice President, Communications and Public Affairs, Exelon   

2009 - 2010

      Senior Vice President, Exelon Business Services Company; Senior Vice President, Generation   

2007 - 2010

      Vice President and Associate General Counsel, Exelon Business Services Company   

2004 - 2007

Hilzinger, Matthew F.

     47      Senior Vice President and Chief Financial Officer, Exelon; Chief Financial Officer, Generation   

2008 - Present

      Senior Vice President and Corporate Controller, Exelon   

2005 - 2008

      Treasurer, Exelon and Generation   

2011 - Present

      Principal Accounting Officer, ComEd; Principal Accounting Officer, PECO   

2005 - 2006

      Vice President, ComEd   

2004 - 2006

Galvanoni, Matthew R.

     38      Chief Accounting Officer, Generation; Vice President, Assistant Corporate Controller, Exelon Business Services Company   

2009 - Present

      Vice President, Comptroller, Accountant and Controller, ComEd; Vice President and Controller, PECO    2007 - 2009
      Director of Financial Reporting and Analysis, Exelon    2006

 

ComEd

 

Name

   Age     

Position

  

Period

Clark, Frank M.

     65      Chairman and Chief Executive Officer, ComEd    2005 - Present
      Director, ComEd    2002 - Present

Pramaggiore, Anne R.

     52      President and Chief Operating Officer, ComEd    2009 - Present
      Executive Vice President, Customer Operations, Regulatory and External Affairs, ComEd    2007 - 2009
      Senior Vice President, Regulatory and External Affairs, ComEd    2005 - 2007

Hooker, John T.

     62      Executive Vice President, Legislative and External Affairs, ComEd    2009 - Present
      Senior Vice President, State Governmental Affairs and Real Estate and Facilities, ComEd    2008 - 2009
      Senior Vice President, State, Legislative and Governmental Affairs, ComEd    2005 - 2008

 

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Name

   Age     

Position

  

Period

Donnelly, Terence R.

     50      Executive Vice President, Operations, ComEd    2009 - Present
      Senior Vice President, Transmission and Distribution, ComEd    2007 - 2009
      Senior Vice President, Technical Services, PECO; Senior Vice President, Technical Services, ComEd    2007 - 2007
      Vice President, Transmission and Substations, Exelon Energy Delivery; Vice President, Transmission and Substations, ComEd    2004 - 2007
      Vice President, Transmission and Substations, PECO    2005 - 2006

Trpik Jr., Joseph R.

     41      Senior Vice President, Chief Financial Officer and Treasurer, ComEd    2009 - Present
      Vice President & Assistant Corporate Controller, Exelon Business Services Company    2007 - 2009
      Vice President and Assistant Corporate Controller, Exelon    2004 - 2009
      Assistant Controller, ComEd    2004 - 2006

Marquez Jr., Fidel

     49      Senior Vice President, Customer Operations, ComEd    2009 - Present
      Vice President of External Affairs and Large Customer Services, ComEd    2007 -2009
      Vice President of External Affairs, Chicago Operations, ComEd    2004 -2006

O’Neill, Thomas S.

     48      Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd    2010 - Present
      Senior Vice President, Exelon    2009 - 2010
      Senior Vice President, New Business Development, Generation;
Senior Vice President, New Business Development, Exelon
   2009 - 2009
      Vice President, New Plant Development, Generation    2007 - 2009
      Vice President, Licensing and Regulatory, Exelon Nuclear    2005 - 2007

Anthony, J. Tyler

     46      Senior Vice President, Distribution Operations, ComEd    2010 - Present
      Vice President, Transmission and Substations, ComEd    2007 - 2010
      Vice President, Transmission and Substations, PECO    2007 - 2007
      Vice President, Outage Planning and Services, Generation    2006 - 2007
      Vice President, Project Management, Exelon Nuclear    2004 - 2006

Waden, Kevin J.

     39      Vice President, Comptroller, Accountant and Controller, ComEd    2009 - Present
      Director of Accounting Operations, ComEd    2007 - 2009
      Director of Financial Reporting and Accounting Research, Exelon Energy Delivery    2003 - 2007

 

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PECO

 

Name

   Age     

Position

  

Period

O’Brien, Denis P.

     50      Executive Vice President, Exelon; Chief Executive Officer, PECO    2007 - Present
      President and Director, PECO    2003 - Present

Adams, Craig L.

     58      Senior Vice President and Chief Operating Officer, PECO    2007 - Present
      Senior Vice President and Chief Supply Officer, Exelon Business Services Company    2004 - 2007

Barnett, Phillip S.

     47      Senior Vice President and Chief Financial Officer, PECO    2007 - Present
      Senior Vice President, Corporate Financial Planning, Exelon    2005 - 2007

Bonney, Paul R.

     52      Vice President, Regulatory Affairs and General Counsel, PECO    2009 - Present
      General Counsel, Vice President & Assistant Secretary, PECO    2007 - 2009
      Vice President & Deputy General Counsel, Regulatory, Exelon Business Services Company    2001 - 2007

Diaz Jr., Romulo L.

     64      Vice President, Governmental and External Affairs, PECO    2009 - Present
      Associate General Counsel, Exelon    2008 - 2009
      City Solicitor, City of Philadelphia    2005 - 2008

Acevedo, Jorge A.

     39      Vice President and Controller, PECO    2009 - Present
      Assistant Treasurer, PECO    2010 - Present
      Assistant Controller, Generation    2007 - 2009
      Director of Accounting, Power Team division of Generation    2003 - 2007

 

ITEM 1A. RISK FACTORS

 

Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond each Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the RMC, which is comprised of officers of the Registrants, to identify and evaluate the most significant risks of the Registrants’ businesses, and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Risk Oversight and Audit Committees of the Exelon Board of Directors and the ComEd and PECO Boards of Directors. In addition, the Exelon Board of Directors’ Generation Oversight and Energy Delivery Oversight Committees, respectively, evaluate risks related to the generation and energy delivery businesses. The risk factors discussed below may adversely affect one or more of the Registrants’ results of operations and cash flows and the market prices of their publicly traded securities. Each of the Registrants has disclosed the material risks known to it to affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may in the future adversely affect its performance or financial condition.

 

The Registrants’ most significant risks arise as a consequence of: (1) Generation’s position as a predominantly nuclear generator selling power into competitive wholesale markets, and (2) the role of both ComEd and PECO as operators of electric transmission and distribution systems in two of the

 

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largest metropolitan areas in the United States. The Registrants’ major risks fall primarily under the following categories:

 

   

Market and Financial Risks. Exelon’s and Generation’s market and financial risks include the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as the price of fuels, in particular the price of natural gas and coal, that drive the wholesale market prices that Generation’s nuclear power plants can command, the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, and the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs.

 

   

Regulatory and Legislative Risks. The Registrants regulatory and legislative risks include changes to the laws and regulations that govern competitive markets and utility cost recovery, and that drive environmental policy. In particular, Exelon’s and Generation’s financial performance may be adversely affected by changes that could affect Generation’s ability to sell power into the competitive wholesale power markets at market-based prices. In addition, potential regulation and legislation regarding climate change and renewable portfolio standards could increase the pace of development of wind energy facilities, which could put downward pressure in some markets on wholesale market prices for electricity from Generation’s nuclear assets, partially offsetting any additional value Exelon and Generation might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future.

 

   

Operational Risks. The Registrants operational risks include those risks inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability and safety of its energy delivery systems are fundamental to Exelon’s ability to protect and grow shareholder value. Additionally, the operating costs of ComEd and PECO and the opinions of customers and regulators of ComEd and PECO are affected by those companies’ ability to maintain the reliability and safety of their energy delivery systems.

 

A discussion of each of these risks and other risk factors is included below.

 

Market and Financial Risks

 

Generation is exposed to price fluctuations in the wholesale power market, which may negatively affect its results of operations. (Exelon and Generation)

 

Generation hedges the price risk associated with the generation it owns, or controls through long-term power purchase agreements. Absent any hedging activity through long-term, fixed price transactions, Generation would be exposed to the risk of rising and falling spot market prices in the markets in which its assets are located, which would mean that Generation’s cash flows would vary accordingly.

 

The wholesale spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Many times, the next unit of electricity will be supplied from generating stations fueled by fossil fuels, and, therefore, the market price of power will reflect the market price of the marginal fuel. As such, changes in the market price of fossil fuels will cause comparable changes to the market price of power. For example, the use of new technologies to recover natural gas from shale deposits is expected to increase natural gas supply and reserves, which will tend to place further downward pressure on natural gas prices and could reduce Generation’s revenue, and, therefore, adversely affect the its financial condition, results of operations and cash flows. Further, in the event that alternative generation resources, such as wind

 

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and solar, are mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation and added to the supply, they could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region, including Generation, would sell their output.

 

The market price for electricity is also affected by changes in the demand for electricity. Poorer than expected economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs can depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on market prices for electricity. The continued sluggish economy in the United States has in fact led to a slow down in the growth of demand for electricity. If this continues, it could adversely affect the Registrants’ ability to pay dividends or fund other discretionary uses of cash such as growth projects. A slow recovery could result in a prolonged depression of or further decline in commodity prices, which could also adversely affect Exelon’s and Generation’s results of operations, cash flows and financial position.

 

In addition to price fluctuations, Generation is exposed to other risks of the wholesale power market that are beyond its control and may negatively affect its results of operations. (Exelon and Generation)

 

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTO’s and ISO’s, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, the retail businesses subject Generation to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that may be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.

 

Unstable Markets. The wholesale spot markets remain evolving markets that vary from region to region and are still developing practices and procedures. Problems in or the failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.

 

Market performance and other factors may decrease the value of decommissioning trust funds and benefit plan assets and increase the related obligations, which then could require significant additional funding. (Exelon, Generation, ComEd and PECO)

 

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy may adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts. The asset values are subject to market fluctuations and will yield uncertain returns, which may fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments may increase the funding requirements to decommission Generation’s nuclear plants. A decline in the market value of the pension and other postretirement benefit plan assets will increase the funding requirements associated

 

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with Exelon’s pension and other postretirement benefit plans. Additionally, Exelon’s pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors are not recoverable from ComEd and PECO customers, the results of operations and financial positions of ComEd and PECO could be negatively affected. Ultimately, if the Registrants are unable to manage the decommissioning trust funds and benefit plan assets and obligations, their results of operations and financial positions could be negatively affected.

 

Unstable capital and credit markets and increased volatility in commodity markets may adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could adversely affect the Registrants’ financial condition, results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

 

The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations. Disruptions in the capital and credit markets can adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under those credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy to reduce collateral-posting requirements, or a reduction in dividend payments or other discretionary uses of cash.

 

In addition, the credit facilities for Exelon, Generation and PECO largely expire in October 2012. Exelon anticipates refinancing these credit facilities, approximately $6.4 billion, in the first half of 2011. Disruptions in the capital and credit markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. The Registrants may choose to establish cost-effective alternative liquidity sources as appropriate.

 

The strength and depth of competition in competitive energy markets depend heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that may affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts such as the financial swap contract between Generation and ComEd as described further in Note 2 of the Combined Notes to Consolidated Financial Statements, which could have a material adverse effect on Exelon’s and Generation’s results of operations and cash flows.

 

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If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards of its trading counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs. (Exelon, Generation, ComEd and PECO)

 

Generation’s trading business is subject to credit quality standards that may require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under trading agreements to provide collateral in the form of letters of credit or cash, which may have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time is dependent on a variety of factors, including (1) the notional amount of trading positions, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry or Generation has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.

 

ComEd’s financial swap contract with Generation and its operating agreement with PJM contain collateral provisions that are affected by its credit rating and market prices. If certain wholesale market conditions exist and ComEd were to lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required under the financial swap contract with Generation to provide collateral in the form of letters of credit or cash, which may have a material adverse effect upon its liquidity. Collateral posting by ComEd under the financial swap will generally increase as forward market prices fall and decrease as forward market prices rise. Conversely, collateral requirements under the PJM operating agreement will generally increase as market prices rise and decrease as market prices fall. Given the relationship to market prices, contract collateral requirements can be volatile. In addition, if ComEd were downgraded, it could experience higher borrowing costs as a result of the downgrade.

 

PECO’s operating agreement with PJM and its power and natural gas procurement contracts contain collateral provisions that are affected by its credit rating. If certain wholesale market conditions exist and PECO were to lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide collateral in the form of letters of credit or cash, which may have a material adverse effect upon its liquidity. PECO’s collateral requirements relating to its natural gas supply contracts are a function of market prices. Collateral posting requirements for PECO with respect to these contracts will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if PECO were downgraded, it could experience higher borrowing costs as a result of the downgrade.

 

Either or both ComEd and PECO could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general or ComEd or PECO in particular has deteriorated. ComEd or PECO could experience a downgrade if the current regulatory environments in Illinois and Pennsylvania become less predictable by materially lowering returns for utilities in the applicable state or adopting other measures to mitigate higher electricity prices. Additionally, the ratings for ComEd or PECO could be downgraded if either company’s financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of ComEd or PECO.

 

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ComEd and PECO conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that ComEd and PECO are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate ComEd and PECO from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ringfencing”) may help avoid or limit a downgrade in the credit ratings of ComEd and PECO in the event of a reduction in the credit rating of Exelon. Despite these ringfencing measures, the credit ratings of ComEd or PECO could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of ComEd or PECO, or both. A reduction in the credit rating of ComEd or PECO could have a material adverse effect on ComEd or PECO, respectively.

 

See Liquidity and Capital Resources—Recent Market Conditions and Security Ratings for further information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.

 

Generation’s financial performance may be negatively affected by price volatility, availability and other risk factors associated with the procurement of nuclear and fossil fuel. (Exelon and Generation)

 

Generation depends on nuclear fuel, coal, natural gas and oil to operate its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. Coal, natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, coal, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that may negatively affect the results of operations for Generation.

 

Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities. (Exelon and Generation)

 

Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions may have on its business, operating results or financial position.

 

Generation buys and sells energy and other products in the wholesale markets and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. The proportion of hedged positions in its power generation portfolio may cause volatility in Generation’s future results of operations.

 

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Generation may not be able to effectively respond to increased demand for energy. (Exelon and Generation)

 

Generation’s financial growth may depend in part on its ability to respond to increased demand for energy. If demand for electricity rises in the future, it may be necessary for the market to increase capacity through the construction of new generating facilities. Development by Generation of new generating facilities would require the commitment of substantial capital resources, including access to the capital markets. The wholesale markets for electricity and certain states’ statutes contemplate that future generation will be built in those markets at the risk of market participants. Thus, the ability of Generation to recover the costs of and to earn an adequate return on any future investment in generating facilities will be dependent on its ability to build, finance and efficiently operate facilities that are competitive in those markets. Additionally, construction of new generating facilities by Generation in markets in which it currently competes would be subject to market concentration tests administered by FERC. If Generation cannot pass these tests administered by FERC, it could be limited in how it responds to increased demand for energy.

 

Financial performance and load requirements may be adversely affected if Generation is unable to effectively manage its power portfolio. (Exelon and Generation)

 

A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with ComEd, PECO and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale market. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results may be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio and effectively handle the changes in the wholesale power markets.

 

Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could negatively impact the Registrants’ results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

 

1999 sale of fossil generating assets. The IRS has challenged Exelon’s 1999 tax position on an involuntary conversion and like-kind exchange transaction. In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions and for the IRS to withdraw its assertion of a $110 million substantial understatement penalty related to the involuntary conversion position. However, Exelon and IRS Appeals failed to reach a settlement on the like-kind exchange position. Exelon expects to initiate litigation on this matter during the second half of 2011. If the IRS is successful in its challenge to the like-kind exchange position, it would accelerate future income tax payments and increase interest expense related to the deferred tax gain that would become currently payable. As of December 31, 2010, Exelon’s and ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $830 million, excluding penalties. If the deferral were successfully challenged by the IRS, Exelon’s and ComEd’s results of operations could also be negatively impacted by up to $230 million (after tax) related to interest expense. In addition to attempting to impose tax on the like-kind exchange position, the IRS has asserted penalties for a substantial understatement of tax, which could result in an after-tax charge of $86 million to Exelon’s and ComEd’s results of operations should the IRS prevail in asserting the penalties. The timing effects of the final resolution of the like-kind exchange matter are unknown. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information.

 

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Tax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeals issues related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by the tax authorities. The Registrants also estimate their ability to utilize tax benefits, including those in the form of carryforwards and tax credits. See Notes 1 and 11 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Increases in customer rates and the impact of economic downturns may lead to greater expense for uncollectible customer balances. Additionally, increased rates could lead to decreased volumes delivered. Both of these factors may decrease ComEd’s and PECO’s results from operations and cash flows. (Exelon, ComEd and PECO)

 

ComEd’s current procurement plan includes purchasing power through contracted suppliers and the spot market. PECO began procuring power at market-based rates through contracted suppliers and the spot market on January 1, 2011 following the end of its transition period. ComEd’s and PECO’s costs of purchased power are charged to customers without a return or profit component. For PECO, purchased natural gas costs are charged to customers with no return or profit component. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas can result in declines in customer usage, lower electric transmission and distribution revenues and potentially additional uncollectible accounts expense for ComEd and PECO as well as lower gas distribution revenues for PECO. Also, ComEd’s and PECO’s cash flows can be affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.

 

In addition to increased purchased power charges for ComEd and PECO customers and purchased natural gas costs for PECO customers, the impact of economic downturns on ComEd and PECO’s customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations may result in an increase in the number of uncollectible customer balances, which would negatively impact ComEd’s and PECO’s results from operations and cash flows. See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk for further discussion of the Registrants’ credit risk.

 

The effects of weather may impact the Registrants’ results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

 

Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues. Extreme weather conditions or damage resulting from storms may stress ComEd’s and PECO’s transmission and distribution systems, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. These extreme conditions may have detrimental effects on ComEd’s and PECO’s results of operations and cash flows.

 

Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual commitments. Extreme weather conditions or storms may affect the availability of generation and its transmission,

 

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limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions can impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, may have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak.

 

Certain long-lived assets recorded on the Registrants’ statements of financial position may become impaired, which would result in write-offs of the impaired amounts. (Exelon, Generation, ComEd and PECO)

 

Long-lived assets represent the single largest asset class on the Registrants’ statement of financial position. Specifically, long-lived assets account for 57%, 48%, 58% and 63% of total assets for Exelon, Generation, ComEd and PECO, respectively, as of December 31, 2010. The Registrants evaluate for impairment the carrying value of long-lived assets to be held and used whenever indications of impairment exist. Factors such as the business climate, including current energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assets for impairment. An impairment would require the Registrants to reduce the long-lived asset through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact on the Registrants’ results of operations.

 

Exelon holds certain investments in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. On an annual basis, Exelon reviews the estimated residual values of these leased assets to determine whether any indications of impairment exist. In determining the estimate of residual value, the expectation of future market conditions, including commodity prices, is considered. An impairment would require Exelon to reduce the value of its investment in the plants through a non-cash charge to expense. Such an impairment could have a material adverse impact on Exelon’s results of operations.

 

Exelon and ComEd had approximately $2.6 billion of goodwill recorded at December 31, 2010 in connection with the merger between PECO and Unicom Corporation, the former parent company of ComEd. Under GAAP, goodwill remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off and expensed, reducing equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Adverse regulatory actions or a fully successful IRS challenge to Exelon’s and ComEd’s like-kind exchange income tax position in combination with changes in significant assumptions used in estimating ComEd’s fair value (e.g., discount and growth rates, utility sector market performance and transactions, operating and capital expenditure requirements and the fair value of debt) could result in an impairment. Such an impairment would result in a non-cash charge to expense, which could have a material impact on Exelon’s and ComEd’s operating results.

 

See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Estimates and Notes 5 and 7 of the Combined Notes to the Consolidated Financial Statements for additional discussion on long-lived asset and goodwill impairments.

 

The Registrants’ businesses are capital intensive and the costs of capital projects may be significant. (Exelon, Generation, ComEd and PECO)

 

The Registrants’ businesses are capital intensive and require significant investments in energy generation and in other internal transmission and distribution infrastructure projects. The Registrants’

 

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results of operations, financial condition, or cash flows could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. See Item 1 of this Form 10-K for further information regarding the Registrants’ potential future capital expenditures.

 

Exelon and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance. (Exelon, Generation, ComEd and PECO)

 

The Registrants have issued certain guarantees of the performance of others, which obligate Exelon and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Registrants. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Due to its significant contractual agreements with ComEd, Generation will be negatively affected in the event of non-performance or change in the creditworthiness of ComEd. (Exelon and Generation)

 

Generation currently provides power under procurement contracts with ComEd for a significant portion of ComEd’s electricity supply requirements. In addition, Generation entered into a financial swap contract with ComEd, effective August 2007, to hedge a portion of ComEd’s electricity supply requirements through May 2013. Consequently, Generation is highly dependent on ComEd’s continued payments under these procurement contracts and would be adversely affected by negative events affecting these agreements, including the non-performance or a significant change in the creditworthiness of ComEd. A default by ComEd under these agreements would have an adverse effect on Generation’s results of operations and financial position.

 

Generation’s business may be negatively affected by competitive electric generation suppliers. (Exelon and Generation)

 

Because retail customers where Generation serves load can switch from their respective energy delivery company to a competitive electric generation supplier for their energy needs, planning to meet Generation’s obligation to provide the supply needed to serve Generation’s share of an electric distribution companies’ default service obligation is more difficult than planning for retail load before the advent of retail competition. Before retail competition, the primary variables affecting projections of load were weather and the economy. With retail competition, another major factor is the ability of retail customers to switch to competitive electric generation suppliers. If fewer of such customers switch from its retail load serving counterparties than Generation anticipates, the load that Generation must serve will be greater than anticipated, which could, if market prices have increased, increase Generation’s costs (due to its need to go to market to cover its incremental supply obligation) more than the increase in Generation’s revenues. If more customers switch than Generation anticipates, the load that Generation must serve will be lower than anticipated, which could, if market prices have decreased, cause Generation to lose opportunities in the market.

 

Regulatory and Legislative Risks

 

The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to adverse regulatory and legislative actions. Fundamental changes in regulation or legislation could disrupt the Registrants’ business plans and adversely affect their operations and financial results. (Exelon, Generation, ComEd and PECO)

 

Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and Generation’s operating results and

 

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cash flows are heavily dependent upon the ability of Generation to sell power at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s, ComEd’s and PECO’s operating results and cash flows are heavily dependent on their ability to recover their costs for the retail purchase and distribution of power to their customers. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, ratemaking agencies and taxing authorities. Fundamental changes in regulations or other adverse legislative actions impacting the Registrants’ businesses would require changes in their business planning models and operations and could adversely affect their results of operations, cash flows and financial position.

 

Regulatory and legislative developments related to climate change and RPS may also significantly affect Exelon’s and Generation’s results of operations, cash flows and financial positions. Various legislative and regulatory proposals to address climate change through GHG emission reductions, if enacted, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase the market price at which all generators in that region, including Generation, may sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. However, regulation or legislation addressing climate change through an RPS could also increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices for electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. The Registrants cannot predict when or whether any of these various legislative and regulatory proposals may become law or what their effect will be on the Registrants.

 

Generation may be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and functioning of the wholesale markets. (Exelon and Generation)

 

Federal and state legislative and regulatory bodies are facing pressures to address consumer concerns that energy prices in wholesale markets are too high because the competitive model is not working, and are therefore facing calls for some form of re-regulation or some other means of reducing wholesale market prices. As the energy markets continue to mature, a low number of wholesale market power participants entering procurement proceedings may also influence how certain regulators and legislators view the effectiveness of these competitive markets.

 

The criticism of restructured electricity markets, which has escalated in recent years as retail rate freezes have expired, is expected to continue in 2011. Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.

 

Approximately 80% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for policies that favor the preservation of competitive wholesale power markets, such as the PJM’s, and (2) the absence of material changes to market structures that would limit or otherwise negatively affect the competitiveness of the PJM market. Generation could also be adversely affected by efforts of state legislatures, such as the New Jersey Capacity Legislation enacted into law on January 28, 2011 and other states seeking to enact similar programs, and regulatory authorities to respond to the concerns of consumers or others about the costs of energy that are reflected through wholesale markets.

 

In addition, FERC’s application of its Order 697 and its subsequent revisions could pose a risk that Generation will have difficulty satisfying FERC’s tests for market-based rates. Since Order 697 became

 

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final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority. Generation’s next submission seeking reauthorization to sell at market-based rates was filed on December 30, 2010 for the PJM region. In its filing, Generation submitted studies showing that it continues to satisfy the tests required by Order 697. Should FERC take a more stringent tack with respect to Order 697 applications, it is possible that Generation’s authority to sell at market-based rates could be in doubt. Generation, however, currently expects that FERC will approve its pending application.

 

On July 21, 2010, the Dodd-Frank Act was enacted into law. Dodd-Frank calls for the Commodity Futures Trading Commission (CFTC), the SEC and the Federal Reserve to regulate the market for over-the-counter (OTC) derivative products. Currently, rulemakings are pending at these agencies, the product of which will be rules that implement the mandates in Dodd-Frank to eliminate the risk of systemic failure of financial markets. The significance of the effect on Generation will depend in part on whether it is determined to be a swap dealer or a qualifying end-user, based on the meaning of those terms established in the final rules. If Generation is deemed a swap dealer, it will be required execute bilateral OTC derivative transactions through an exchange or central clearinghouse. This could require Generation to tie up substantial additional capital in order to satisfy exchange-based margin requirements.

 

Even if Generation is not deemed a swap dealer, the rules could impose burdens on market participants to such an extent that liquidity in the bilateral OTC derivative market decreases substantially. As Generation’s hedging program relies heavily on its ability to trade actively in the current bilateral OTC derivatives market, the effect of the new rules could significantly impede Generation’s ability to meet its hedge targets. Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operation, cash flows or financial position.

 

Generation’s affiliation with ComEd and PECO, together with the presence of a substantial percentage of Generation’s physical asset base within the ComEd and PECO service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding ComEd and/or PECO retail rates result in settlements or legislative or regulatory requirements funded in part by Generation. (Exelon and Generation)

 

Generation has significant generating resources within the service areas of ComEd and PECO and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with ComEd and PECO and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups may question or challenge costs incurred by ComEd or PECO, including transactions between Generation, on the one hand, and ComEd or PECO, on the other hand, regardless of any previous regulatory processes or approvals underlying those transactions. The prospect of such challenges may increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges may subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators may seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.

 

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters. (Exelon, Generation, ComEd and PECO)

 

The businesses in which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in

 

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which the Registrants conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements can subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies is one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

 

If application of Section 316(b), which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. On December 8, 2010, pursuant to discussions with the NJDEP regarding the application of Section 316(b) of the Clean Water Act to Oyster Creek, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019, ten years before the expiration of its operating license in 2029.

 

Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.

 

In some cases, a third party who has acquired assets from a Registrant has assumed the liability the Registrant may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee may be limited by the financial resources of the transferee. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Changes in ComEd’s and PECO’s terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which may introduce time delays in effectuating rate changes. (Exelon, ComEd and PECO)

 

ComEd and PECO are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for ComEd or PECO to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates can be adjusted, including recovery mechanisms for costs associated with the procurement of electricity or gas, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.

 

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In certain instances, ComEd and PECO may agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval.

 

ComEd and PECO cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania or Federal regulators for establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR and default service obligations to provide electricity and natural gas to certain groups of customers in its service area who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of ComEd and PECO, as applicable, to recover their costs and could have a material adverse effect on ComEd’s and PECO’s results of operations, cash flows and financial position. See Note 2 of the Combined Notes to the Consolidated Financial Statements for information on appeals in connection with ComEd’s 2007 Illinois electric distribution rate case.

 

Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the results of operations and cash flows of ComEd and PECO. (Exelon, ComEd and PECO)

 

Changes to current state legislation or the development of Federal legislation that requires the use of renewable and alternate fuel sources, such as wind, solar, biomass and geothermal, could significantly impact ComEd and PECO, especially if timely cost recovery is not allowed. The impact could include increased costs for RECs and purchased power and increased rates for customers.

 

Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact ComEd and PECO, if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, ComEd and PECO. For additional information, see ITEM 1. Business “Environmental Regulation-Renewable and Alternative Energy Portfolio Standards”.

 

ComEd and PECO are likely to be subject to higher transmission operating costs in the future as a result of PJM’s RTEP. (Exelon, ComEd and PECO)

 

Uncertainties exist as to the construction of new transmission facilities, their cost and how those costs will be allocated to transmission system participants and customers. In accordance with a FERC order and related settlement, PJM’s RTEP requires the costs of new transmission facilities to be allocated across the entire PJM footprint for new facilities greater than or equal to 500 kV, and requires costs of new facilities less than 500 kV to be allocated to the beneficiaries of the new facilities. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit remanded to FERC its decision related to allocation of new facilities 500 kV and above for further proceedings. See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon, ComEd and PECO. (Exelon, ComEd and PECO)

 

As of December 31, 2010, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their

 

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businesses no longer meets the criteria, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time extraordinary item in their Consolidated Statements of Operations. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2010, the extraordinary gain could have been as much as $1.8 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2010, the extraordinary charge could have been as much as $534 million (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record the same amount of extraordinary gain and charge related to ComEd’s and PECO’s regulatory assets and liabilities, respectively. Further, Exelon would record a charge against OCI (before taxes) of up to $2.7 billion and $45 million for ComEd and PECO, respectively, related to Exelon’s regulatory assets associated with its defined benefit postretirement plans. The impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which could be significant and at least partially offset the extraordinary gain discussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd and PECO to pay dividends under Federal and state law and cause significant volatility in future results of operations. See Notes 1, 2 and 7 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s goodwill, respectively.

 

Exelon and Generation may incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change. (Exelon and Generation)

 

Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. In 2009, select Northeast and Mid-Atlantic states implemented a model rule, developed via the RGGI, to regulate CO2 emissions from fossil-fired generation. If carbon reduction regulation or legislation becomes effective, Exelon and Generation may incur costs either to limit further the GHG emissions from their operations or to procure emission allowance credits. The nature and extent of environmental regulation may also impact the ability of Exelon and its subsidiaries to meet the GHG emission reduction targets of Exelon 2020. For example, more stringent permitting requirements may preclude the construction of lower-carbon nuclear and gas-fired power plants. Similarly, a Federal RPS could increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change, see “Global Climate Change” in ITEM 1 of this Form 10-K and Note 18 of the Combined Notes to Consolidated Financial Statements in ITEM 8 of this Form 10-K.

 

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards. (Exelon, Generation, ComEd and PECO)

 

As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO as operator of a natural gas distribution system is also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with or changes in the reliability standards may subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC and PAPUC impose certain distribution reliability standards on ComEd and PECO, respectively. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.

 

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The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could have a material adverse effect on their results of operations, financial positions and cash flows. (Exelon, Generation, ComEd and PECO)

 

The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in Note 18 of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures that could have a material adverse effect on the Registrants’ results of operations.

 

Operational Risks

 

The Registrants’ employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of the energy industry. (Exelon, Generation, ComEd and PECO)

 

Employees and contractors throughout the organization work in, and customers and the general public may be exposed to, potentially dangerous environments near operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. Significant risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.

 

War, acts and threats of terrorism, natural disaster, pandemic and other significant events may adversely affect Exelon’s results of operations, its ability to raise capital and its future growth. (Exelon, Generation, ComEd and PECO)

 

Exelon does not know the impact that potential terrorist attacks could have on the industry in general and on Exelon in particular. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, Exelon faces a risk that its operations would be direct targets of, or indirect casualties of, an act of terror. Any retaliatory military strikes or sustained military campaign may affect its operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Additionally, natural disasters and other events that have an adverse effect on the economy in general may adversely affect Exelon’s operations and its ability to raise capital. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also may affect Exelon’s results of operations and its ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.

 

Further, the physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena, could affect some, or all, of the Registrant’s operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for Exelon’s and Generation’s continued operation, particularly the cooling of generating units.

 

Exelon would be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate its generating and transmission and distribution assets could be affected, resulting in decreased service levels and increased costs.

 

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Generation’s financial performance may be negatively affected by matters arising from its ownership and operation of nuclear facilities. (Exelon and Generation)

 

Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including ComEd and PECO. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.

 

Nuclear refueling outages. Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 26 days in duration for the nuclear plants operated by Generation. The total number of refueling outages, along with their duration, can have a significant impact on Generation’s results of operations. When refueling outages at wholly and co-owned plants last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each 26-day outage, depending on the capacity of the station, will decrease the total nuclear annual capacity factor between 0.3% and 0.5%.

 

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of Generation’s operations. Certain of Generation’s nuclear units have previously had a limited number of fuel performance issues. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.

 

Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. Through the NRC’s “waste confidence” rule, the NRC has determined that, if necessary, spent fuel generated in any reactor can be stored safely and without significant environmental impacts for at least 60 years beyond the licensed life for operation, which may include the term of a revised or renewed license of that reactor, at its spent fuel storage basin or at either onsite or offsite independent spent fuel storage installations. Any regulatory action relating to the timing and availability of a repository for SNF may adversely affect Generation’s ability to decommission fully its nuclear units. Furthermore, under its contract with the DOE, Generation would be required to pay the DOE a one-time SNF storage fee including interest of approximately $1 billion as of December 31, 2010, prior to the first delivery of SNF. Generation currently estimates 2020 to be the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information on the spent nuclear fuel obligation.

 

License renewals. Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of any renewed license period. If the NRC does not renew the operating licenses for Generation’s nuclear stations or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. In addition, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments.

 

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Should a national policy for the disposal of SNF not be developed, the unavailability of a repository for SNF could become a consideration by the NRC during future nuclear license renewal proceedings, including applications for new licenses.

 

Regulatory risk. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and significantly affect Generation’s results of operations or financial position. Events at nuclear plants owned by others, as well as those owned by Generation, may cause the NRC to initiate such actions.

 

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners. For the plant not wholly owned by Generation and operated by PSEG, Salem Units 1 and 2, from which Generation receives its share of the plant’s output, Generation’s results of operations are dependent on the operational performance of the co-owner operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s results of operations or financial position. In addition, closure of generating plants owned by others, or extended interruptions of their operations, could have effects on transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.

 

Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident can be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned by Generation or owned by others, may exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations or financial position. Additionally, an accident or other significant event at a nuclear plant within the United States, owned by others or Generation, may result in increased regulation and reduced public support for nuclear-fueled energy and significantly affect Generation’s results of operations or financial position. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional discussion of nuclear insurance.

 

Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance. As of January 1, 2011, the required amount of nuclear liability insurance is $375 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.6 billion limit for a single incident.

 

Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In recent years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will continue at all.

 

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Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s two units that have been retired) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the decommissioning trust funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.

 

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. The performance of capital markets also can significantly affect the value of the trust funds. Currently, Generation is making contributions to the trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from ComEd customers or from the previous owners of Clinton, TMI Unit No. 1 and Oyster Creek generating stations, if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation were unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units may be negatively affected. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Generation’s cash flows and financial position may be significantly adversely affected. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Generation’s financial performance may be negatively affected by risks arising from its ownership and operation of hydroelectric facilities. (Exelon and Generation)

 

FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. The license for the Conowingo Hydroelectric Project expires August 31, 2014, and the license for the Muddy Run Pumped Storage Project expires on September 1, 2014. Generation cannot predict whether it will receive all the regulatory approvals for the renewed license of its hydroelectric facilities. If FERC does not renew the operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation may also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions may be imposed as part of the license renewal process that may adversely affect operations, may require a substantial increase in capital expenditures or may result in increased operating costs and significantly affect Generation’s results of operations or financial position. Similar effects may result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.

 

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ComEd’s and PECO’s operating costs, and customers’ and regulators’ opinions of ComEd and PECO, are affected by their ability to maintain the availability and reliability of their delivery systems. (Exelon, ComEd and PECO)

 

Failures of the equipment or facilities used in ComEd’s and PECO’s delivery systems can interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including weather. Those failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction and the level of regulatory oversight and ComEd’s and PECO’s maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd can be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers.

 

ComEd’s and PECO’s respective ability to deliver electricity, their operating costs and their capital expenditures may be negatively affected by transmission congestion. (Exelon, ComEd and PECO)

 

Demand for electricity within ComEd’s and PECO’s service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficient availability of electric supply to meet customer demand could jeopardize ComEd and PECO’s ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring ComEd and PECO to upgrade or expand their respective transmission systems through additional capital expenditures.

 

Failure to attract and retain an appropriately qualified workforce may negatively impact the Registrants’ results of operations. (Exelon, Generation, ComEd and PECO)

 

Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, may lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their results of operations could be negatively affected.

 

The Registrants are subject to information security risks. (Exelon, Generation, ComEd and PECO)

 

The Registrants face information security risks as the owner-operators of generation, transmission and distribution facilities. A security breach of the Registrants’ information systems could impact the reliability of the generation fleet and/or reliability of the transmission and distribution system or subject them to financial harm associated with theft or inappropriate release of certain types of information. The Registrants cannot accurately assess the probability that a security breach may occur, despite the measures taken by the Registrants to prevent such a breach, and are unable to quantify the potential impact of such an event.

 

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The Registrants may make acquisitions that do not achieve the intended financial results. (Exelon, Generation, ComEd and PECO)

 

The Registrants may make investments and pursue mergers and acquisitions that fit their strategic objectives and improve their financial performance. It is possible that FERC or state public utility commission regulations may impose certain other restrictions on such transactions. Achieving the anticipated benefits of an investment is subject to a number of uncertainties, and failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial condition, operating results and prospects.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

Exelon, Generation, ComEd and PECO

 

None.

 

ITEM 2. PROPERTIES

 

Generation

 

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2010:

 

Station

 

Location

    No. of
Units
    Percent
Owned (a)
    Primary
Fuel Type
    Primary
Dispatch

Type (b)
    Net
Generation
Capacity (MW)  (c)
 

Nuclear (d)

           

Braidwood

    Braidwood, IL        2         Uranium        Base-load        2,360   

Byron

    Byron, IL        2         Uranium        Base-load        2,336   

Clinton

    Clinton, IL        1         Uranium        Base-load        1,067   

Dresden

    Morris, IL        2         Uranium        Base-load        1,751   

LaSalle

    Seneca, IL        2         Uranium        Base-load        2,286   

Limerick

    Limerick Twp., PA        2         Uranium        Base-load        2,289   

Oyster Creek

    Forked River, NJ        1         Uranium        Base-load        625 (e) 

Peach Bottom

    Peach Bottom Twp., PA        2       50       Uranium        Base-load        1,148 (f) 

Quad Cities

    Cordova, IL        2       75       Uranium        Base-load        1,345 (f) 

Salem

    Hancock’s Bridge, NJ        2       42.59       Uranium        Base-load        1,003 (f) 

Three Mile Island

    Londonderry Twp, PA        1         Uranium        Base-load        837  
                 
              17,047   

Fossil (Steam Turbines)

  

       

Conemaugh

    New Florence, PA        2       20.72       Coal        Base-load        352 (f) 

Cromby 1

    Phoenixville, PA        1         Coal        Intermediate        144 (g) 

Cromby 2

    Phoenixville, PA        1         Oil/Gas        Intermediate        201 (g) 

Eddystone 1, 2

    Eddystone, PA        2         Coal        Intermediate        588 (g) 

Eddystone 3, 4

    Eddystone, PA        2         Oil/Gas        Intermediate        760   

Fairless Hills

    Falls Twp, PA        2         Landfill Gas        Peaking        60   

Handley 4, 5

    Fort Worth, TX        2         Gas        Peaking        870   

Handley 3

    Fort Worth, TX        1         Gas        Intermediate        395   

Keystone

    Shelocta, PA        2       20.99       Coal        Base-load        357 (f) 

Mountain Creek 6, 7

    Dallas, TX        2         Gas        Peaking        240   

Mountain Creek 8

    Dallas, TX        1         Gas        Intermediate        565   

Schuylkill

    Philadelphia, PA        1         Oil        Peaking        166   

Wyman

    Yarmouth, ME        1       5.89       Oil        Intermediate        36 (f) 
                 
              4,734   

 

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Station

 

Location

    No. of
Units
    Percent
Owned (a)
    Primary
Fuel Type
    Primary
Dispatch

Type (b)
    Net
Generation
Capacity (MW)  (c)
 

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        29   

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   

New Boston

    South Boston, MA        1         Oil        Peaking        12   

Pennsbury

    Falls Twp., PA        2         Landfill Gas        Peaking        6   

Richmond

    Philadelphia, PA        2         Oil        Peaking        96   

Salem

    Hancock’s Bridge, NJ        1       42.59       Oil        Peaking        16 (f) 

Schuylkill

    Philadelphia, PA        2         Oil        Peaking        30   

Southeast Chicago

    Chicago, IL        8         Gas        Peaking        296   

Southwark

    Philadelphia, PA        4         Oil        Peaking        52   
                 
              1,442   

Fossil (Internal Combustion/Diesel)

  

     

Conemaugh

    New Florence, PA        4       20.72       Oil        Peaking        2 (f) 

Cromby

    Phoenixville, PA        1         Oil        Peaking        3   

Delaware

    Philadelphia, PA        1         Oil        Peaking        3   

Keystone

    Shelocta, PA        4       20.99       Oil        Peaking        2 (f) 

Schuylkill

    Philadelphia, PA        1         Oil        Peaking        3   
                 
              13   

Hydroelectric and Renewable (h)

  

         

AgriWind

    Bureau Co., IL        4       99       Wind        Base-load        8 (f) 

Blue Breezes

    Faribault Co., MN        2         Wind        Base-load        3   

Bluegrass Ridge

    Gentry Co., MO        27       99       Wind        Base-load        56 (f) 

Brewster

    Jackson Co., MN        6       94-99        Wind        Base-load        6 (f) 

Cassia

    Twin Falls Co., ID        14         Wind        Base-load        29   

Cisco

    Jackson Co., MN        4       99       Wind        Base-load        8 (f) 

City Solar

    Chicago, IL        n.a.          Solar        Base-load        10   

Conception

    Nodaway Co., MO        24         Wind        Base-load        50   

Conowingo

    Harford Co., MD        11         Hydroelectric        Base-load        572   

Cow Branch

    Atchinson Co., MO        24         Wind        Base-load        50   

Cowell

    Pipestone Co., MN        1      </