10-K 1 d283520d10k.htm FORM 10-K FORM 10-K
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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, 2011

 

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


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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, 2011, was as follows:

 

Exelon Corporation Common Stock, without par value

   $ 28,372,622,746

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, 2012 was as follows:

 

Exelon Corporation Common Stock, without par value

   663,640,976

Exelon Generation Company, LLC

   not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

   127,016,529

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.

 

 

 


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TABLE OF CONTENTS

 

     Page No.  

GLOSSARY OF TERMS AND ABBREVIATIONS

     1   

FILING FORMAT

     4   

FORWARD-LOOKING STATEMENTS

     4   

WHERE TO FIND MORE INFORMATION

     4   

PART I

     

ITEM 1.

  

BUSINESS

     5   
  

General

     5   
  

Exelon Generation Company, LLC

     6   
  

Commonwealth Edison Company

     17   
  

PECO Energy Company

     19   
  

Employees

     24   
  

Environmental Regulation

     24   
  

Executive Officers of the Registrants

     29   

ITEM 1A.

  

RISK FACTORS

     35   

ITEM 1B.

  

UNRESOLVED STAFF COMMENTS

     60   

ITEM 2.

  

PROPERTIES

     61   
  

Exelon Generation Company, LLC

     61   
  

Commonwealth Edison Company

     63   
  

PECO Energy Company

     64   

ITEM 3.

  

LEGAL PROCEEDINGS

     65   
  

Exelon Corporation

     65   
  

Exelon Generation Company, LLC

     65   
  

Commonwealth Edison Company

     65   
  

PECO Energy Company

     65   

ITEM 4.

  

MINE SAFETY DISCLOSURES

     65   

PART II

     

ITEM 5.

  

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

     66   

ITEM 6.

  

SELECTED FINANCIAL DATA

     70   
  

Exelon Corporation

     70   
  

Exelon Generation Company, LLC

     71   
  

Commonwealth Edison Company

     72   
  

PECO Energy Company

     73   

ITEM 7.

  

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

     74   
  

Exelon Corporation

     74   
  

General

     74   
  

Executive Overview

     74   
  

Critical Accounting Policies and Estimates

     93   
  

Results of Operations

     106   
  

Liquidity and Capital Resources

     132   
  

Exelon Generation Company, LLC

     160   
  

Commonwealth Edison Company

     162   
  

PECO Energy Company

     164   

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     148   
  

Exelon Corporation

     148   
  

Exelon Generation Company, LLC

     161   
  

Commonwealth Edison Company

     163   
  

PECO Energy Company

     165   

 

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     Page No.  

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     166   
  

Exelon Corporation

     174   
  

Exelon Generation Company, LLC

     179   
  

Commonwealth Edison Company

     184   
  

PECO Energy Company

     189   
  

Combined Notes to Consolidated Financial Statements

     194   
  

1. Significant Accounting Policies

     194   
  

2. Regulatory Matters

     207   
  

3. Merger and Acquisitions

     226   
  

4. Accounts Receivable

     231   
  

5. Property, Plant and Equipment

     232   
  

6. Jointly Owned Electric Utility Plant

     235   
  

7. Intangible Assets

     236   
  

8. Fair Value of Financial Assets and Liabilities

     239   
  

9. Derivative Financial Instruments

     257   
  

10. Debt and Credit Agreements

     271   
  

11. Income Taxes

     278   
  

12. Asset Retirement Obligations

     289   
  

13. Retirement Benefits

     296   
  

14. Corporate Restructuring and Plant Retirements

     312   
  

15. Preferred Securities

     314   
  

16. Common Stock

     315   
  

17. Earnings Per Share and Equity

     322   
  

18. Commitments and Contingencies

     322   
  

19. Supplemental Financial Information

     341   
  

20. Segment Information

     350   
  

21. Related Party Transactions

     353   
  

22. Quarterly Data

     359   

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     361   

ITEM 9A.

  

CONTROLS AND PROCEDURES

     361   
  

Exelon Corporation

     361   
  

Exelon Generation Company, LLC

     361   
  

Commonwealth Edison Company

     361   
  

PECO Energy Company

     361   

ITEM 9B.

  

OTHER INFORMATION

     361   
  

Exelon Corporation

     361   
  

Exelon Generation Company, LLC

     361   
  

Commonwealth Edison Company

     361   
  

PECO Energy Company

     362   

PART III

     

ITEM 10.

  

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     363   
  

Exelon Corporation

     363   
  

Exelon Generation Company, LLC

     363   
  

Commonwealth Edison Company

     364   
  

PECO Energy Company

     366   

ITEM 11.

  

EXECUTIVE COMPENSATION

     369   

 

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     Page No.  

ITEM 12.

  

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

     433   

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

     437   

ITEM 14.

  

PRINCIPAL ACCOUNTING FEES AND SERVICES

     438   
  

Exelon Corporation

     438   
  

Exelon Generation Company, LLC

     438   
  

Commonwealth Edison Company

     438   
  

PECO Energy Company

     438   

PART IV

     

ITEM 15.

   EXHIBITS, FINANCIAL STATEMENT SCHEDULES      440   

SIGNATURES

     465   
  

Exelon Corporation

     465   
  

Exelon Generation Company, LLC

     466   
  

Commonwealth Edison Company

     467   
  

PECO Energy Company

     468   

CERTIFICATION EXHIBITS

     469   

 

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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

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

Block contracts

   Forward Purchase Energy Block Contracts

CAIR

   Clean Air Interstate Rule

CAISO

   California ISO

CAMR

   Federal Clean Air Mercury Rule

CERCLA

   Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended

CFL

   Compact Fluorescent Light

Clean Air Act

   Clean Air Act of 1963, as amended

Clean Water Act

   Federal Water Pollution Control Amendments of 1972, as amended

Competition Act

   Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996

Constellation

   Constellation Energy Group, Inc.

CPI

   Consumer Price Index

CSAPR

   Cross-State Air Pollution Rule

CTC

   Competitive Transition Charge

DOE

   United States Department of Energy

 

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Other Terms and Abbreviations

DOJ

   United States Department of Justice

DSP Program

   Default Service Provider Program

EE&C

   Energy Efficiency and Conservation/Demand Response

EGS

   Electric Generation Supplier

EIMA

   Illinois Senate Bill 1652 and Illinois House Bill 3036

EPA

   United States Environmental Protection Agency

ERCOT

   Electric Reliability Council of Texas

ERISA

   Employee Retirement Income Security Act of 1974, 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

GRT

   Gross Receipts Tax

GSA

   Generation Supply Adjustment

GWh

   Gigawatt hour

HAP

   Hazardous air pollutants

Health Care Reform Acts

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

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

 

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Other Terms and Abbreviations

NERC

   North American Electric Reliability Corporation

NJDEP

   New Jersey Department of Environmental Protection

Non-Regulatory Agreements Units

   Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting

NOV

   Notice of Violation

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

POR

   Purchase of Receivables

PPA

   Power Purchase Agreement

PCCA

   Pennsylvania Climate Change Act

PRP

   Potentially Responsible Parties

Price-Anderson Act

   Price-Anderson Nuclear Industries Indemnity Act of 1957

PSEG

   Public Service Enterprise Group Incorporated

PURTA

   Pennsylvania Public Realty Tax Act

PV

   Photovoltaic

RCRA

   Resource Conservation and Recovery Act of 1976, as amended

REC

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

Regulatory Agreement Units

   Nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting

RES

   Retail Electric Suppliers

RFP

   Request for Proposal

Rider

   Reconcilable Surcharge Recovery Mechanism

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

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

Toxics Rule

   U.S. EPA Mercury and Air Toxics Rule

VIE

   Variable Interest Entity

 

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FILING FORMAT

 

This combined Annual Report on 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 OPERATIONS, (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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PART I

 

ITEM 1. BUSINESS

 

General

 

Corporate Structure and Business and Other Information

 

Exelon, incorporated in Pennsylvania in February 1999, is a utility services holding company engaged, through its principal subsidiaries, Generation, in the energy generation business, and ComEd and PECO, in the energy delivery businesses discussed below. 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.

 

Operating Segments

 

See Note 20 of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s operating segments.

 

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Proposed Merger with Constellation Energy Group, Inc.

 

On April 28, 2011, Exelon and Constellation announced that they signed an agreement and plan of merger to combine the two companies in a stock-for-stock transaction. Under the merger agreement, Constellation’s shareholders will receive 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Constellation is a leading competitive supplier of power, natural gas and energy products and services for homes and businesses across the continental United States. It owns a diversified fleet of generating units, totaling approximately 12,000 megawatts of generating capacity, and is a leading advocate for clean, environmentally sustainable energy sources, such as solar power and nuclear energy. Baltimore Gas and Electric Company (BGE), Constellation’s regulated utility, delivers electricity and natural gas in central Maryland. The resulting company will retain the Exelon name and be headquartered in Chicago. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on the Constellation transaction.

 

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 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, 2011, Generation owned generation resources with an aggregate net capacity of 25,544 MW, including 17,115 MW of nuclear capacity. Generation controlled another 5,025 MW of capacity through long-term contracts.

 

Generation’s wholesale marketing unit, Power Team, utilizes 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, and is subject to FERC’s 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. 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 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 FERC.

 

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RTOs exist in a number of regions to provide transmission service across multiple transmission systems. CAISO, PJM, MISO, ISO-NE and Southwest Power Pool, have been approved by FERC 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.

 

Generating Resources

 

At December 31, 2011, the generating resources of Generation consisted of the following:

 

Type of Capacity

   MW  

Owned generation assets (a)

  

Nuclear

     17,115  

Fossil

     5,890  

Hydroelectric/Renewable

     2,539  
  

 

 

 

Owned generation assets

     25,544  

Long-term contracts (b)

     5,025  
  

 

 

 

Total generating resources

     30,569  
  

 

 

 

 

(a) See “Fuel” for sources of fuels used in electric generation.
(b) 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 35% of capacity); Midwest includes the operations in Illinois, Indiana, Michigan and Minnesota (approximately 45% of capacity); and the South and West includes operations primarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and Oregon (approximately 20% of capacity).

 

Nuclear Facilities

 

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with an aggregate of 17,115 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 both 2011 and 2010, electric supply (in GWh) generated from the nuclear generating facilities was 82% 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.

 

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.

 

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During 2011 and 2010, the nuclear generating facilities operated by Generation achieved capacity factors of 93.3% and 93.9%, 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, 2011, the NRC categorized each unit operated by Generation, with the exception of Byron Unit 2 and Limerick Unit 2, in the Licensee Response Column, which is the highest performance band. The NRC categorized Byron Unit 2 and Limerick Unit 2 in the Regulatory Response Column, which is the second 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.

 

On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. For additional information on the NRC actions related to the Japan Earthquake and Tsunami and the industry’s response, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Executive Overview.

 

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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. Additionally, PSEG has 40-year operating licenses from the NRC and on June 30, 2011, received 20-year operating license renewals for Salem Units 1 and 2. In December 8, 2010, in connection with an Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. 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

     1        1988        2026  
     2        1988        2027  

Byron

     1        1985        2024  
     2        1987        2026  

Clinton

     1        1987        2026  

Dresden (b)

     2        1970        2029  
     3        1971        2031  

LaSalle

     1        1984        2022  
     2        1984        2023  

Limerick (c)

     1        1986        2024  
     2        1990        2029  

Oyster Creek (b)(d)

     1        1969        2029  

Peach Bottom (b)

     2        1974        2033  
     3        1974        2034  

Quad Cities (b)

     1        1973        2032  
     2        1973        2032  

Salem (b)

     1        1977        2036  
     2        1981        2040  

Three Mile Island (b)

     1        1974        2034  

 

(a) Denotes year in which nuclear unit began commercial operations.
(b) Stations for which the NRC has issued a renewed operating licenses.
(c) On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years.
(d) In December, 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 June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. 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 except for Oyster Creek.

 

Nuclear Uprate Program. Generation has announced a series of planned power uprates across its nuclear fleet that would result in between 1,175 and 1,300 MWs at an overnight cost of approximately $3.30 billion in 2011 dollars. Overnight costs do not include financing costs or cost escalation. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately 75% of the planned uprate MWs, are

 

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underway at the Limerick, Three Mile Island and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The remaining uprate MWs will come from additional projects across Generation’s nuclear fleet beginning in 2012 and ending in 2017. At 1,300 nuclear-generated MWs, the uprates would displace 6 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and 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, 2011, Generation has added 240 MWs of nuclear generation through its uprate program.

 

New Nuclear 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 necessary should Exelon 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 site would be made based on then-current economics. The original COL project spent the authorized $100 million. The Exelon board authorized an additional $30 million for the ESP project. The total project costs as of December 31, 2011 were $16 million. The current NRC review and approval schedule supports issuance of the ESP in late 2015.

 

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.

 

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As of December 31, 2011, Generation had approximately 56,300 SNF assemblies (13,500 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 decommissioning. The following table describes the current status of Generation’s SNF storage facilities.

 

Site

   Date for loss of full core reserve (a)  

Braidwood

     Dry cask storage in operation   

Byron

     Dry cask storage in operation   

Clinton

     2016  

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.

 

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 received approval for its Peach Bottom and LaSalle stations that will allow it to store LLRW from its remaining stations that have limited capacity. Generation now has enough storage capacity to store all Class B and C LLRW for the life of all stations in Generation’s 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.

 

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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.

 

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 $183 million at December 31, 2011. As of December 31, 2011, NDT funds set aside to pay for these obligations were $351 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, LLC (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 2011 and 2010, electric supply (in GWh) generated from owned fossil, hydroelectric and renewable generating facilities was 7% and 6%, respectively, 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.

 

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar photovoltaic (PV) project under development in northern Los Angeles County, California, from First Solar, which developed and will

 

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build, operate, and maintain the project. Construction has started, with the first portion of the site expected to come online in late 2012 and full operation planned for late 2013. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant. Exelon expects to invest up to $713 million in equity in the project through 2013. The DOE’s Loan Programs Office issued a loan guarantee of up to $646 million to support project financing for Antelope Valley. Exelon expects the total investment of up to $1.36 billion to be accretive to earnings beginning in 2013 and to be accretive to cash flows starting in 2013. The project is expected to have stable earnings and cash flow profiles due to the PPA. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Antelope Valley acquisition.

 

Wolf Hollow Generating Station. On August 24, 2011, Generation completed the acquisition of the equity interest of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, for a purchase price of $311 million pursuant to which Generation added 720 MWs of capacity within the ERCOT power market. Generation recognized a $42 million gain as part of the transaction. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Wolf Hollow acquisition.

 

Exelon Wind. In 2010, Generation acquired 735 MWs of installed, operating wind capacity located in eight states for approximately $893 million in cash. On January 1, 2012, Michigan Wind 2, one of the Exelon Wind development projects acquired in 2010, began commercial operations. The facility has a capacity of approximately 90MWs. In addition, Generation is currently developing additional wind projects in Michigan with a combined capacity of approximately 140 MWs. See Note 3 and Note 1 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Exelon Wind acquisition and new site development costs, respectively.

 

Plant Retirements. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; on December 31, 2011, Cromby Unit 2 was retired and Eddystone Unit 2 will retire on May 31, 2012. 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. Generation plans to file license applications with FERC for both facilities in August 2012. For those plants located within the control areas administered by PJM, notice is required to be provided before a plant can be retired.

 

Insurance. Generation maintains business interruption insurance for its wind and solar PV projects, and delay in start-up insurance for its wind and solar PV projects currently under construction. 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’s and Generation’s financial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES—Generation.

 

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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, 2011:

 

Seller

   Location    Expiration    Capacity (MW)  

Kincaid Generation, LLC

   Kincaid, Illinois    2013      1,108  

Tenaska Georgia Partners, L.P. (a)

   Franklin, Georgia    2030      945  

Tenaska Frontier Partners, Ltd. (b)

   Shiro, Texas    2020      830  

Green Country Energy, LLC (c)

   Jenks, Oklahoma    2022      778  

Elwood Energy, LLC

   Elwood, Illinois    2012      775  

Old Trail Windfarm, LLC

   McLean, Illinois    2026      198  

Others (d)

   Various    2012 to 2028      391  
        

 

 

 

Total

           5,025  
        

 

 

 

 

(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, L.P. through a PPA with Georgia Power, a subsidiary of Southern Company for a 20-year period that began on June 1, 2010.
(b) On December 17, 2009, Generation entered into a PPA with Entergy Texas, Inc. (ETI) to sell 150 MWs through April 30, 2011 and 300 MWs thereafter of capacity and energy from the Frontier Generating Station. The term of the PPA is approximately 10 years.
(c) 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.
(d) Includes long-term capacity contracts with six counterparties.

 

Fuel

 

The following table shows sources of electric supply in GWh for 2011 and estimated for 2012:

 

     Source of Electric Supply (a)  
         2011              2012 (Est.)      

Nuclear

     139,297        141,316  

Purchases—non-trading portfolio

     18,908        18,397  

Fossil and renewable

     11,638        16,466  
  

 

 

    

 

 

 

Total supply

     169,843        176,179  
  

 

 

    

 

 

 

 

(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 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 2017. 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.

 

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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.

 

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 2012 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, 2011, the percentage of expected generation hedged was 88%-91%, 61%-64%, and 32%-35% for 2012, 2013 and 2014, 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

 

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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.

 

At December 31, 2011, Generation’s short and long-term commitments relating to the sale and purchase 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)
 

2012

   $ 177      $ 11      $ 1,150      $ 9  

2013

     71        —           834        6  

2014

     63        —           346        —     

2015

     61        —           200        —     

2016

     61        —           177        —     

Thereafter

     478        —           737        —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 911      $ 11      $ 3,444      $ 15  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(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, 2011, 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.

 

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.

 

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 2012 are as follows:

 

(in millions)

      

Nuclear fuel (a)

   $ 1,173  

Production plant

     844  

Uprates

     450  

Renewable energy projects (b)

     1,301  
  

 

 

 

Total

   $ 3,768  
  

 

 

 

 

(a) Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant.
(b) Includes expenditures for Antelope Valley and Exelon Wind development projects.

 

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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 11,400 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 2012 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 July 20, 2011 and was 23,753 MWs; its highest peak load during a winter season occurred on January 15, 2009 and was 16,328 MWs.

 

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, 2011, approximately 380,300 retail customers representing approximately 56% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier. 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 an 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 kWs continues for all customers who do not or cannot choose a competitive electric generation supplier or who choose to return to ComEd 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 kWs or greater, as this group of customers has previously been declared competitive. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

 

Legislation to Modernize Electric Utility Infrastructure and to Update Illinois Ratemaking Process. On October 26, 2011, the Illinois General Assembly overrode the Governor’s veto of the Illinois Energy Infrastructure Modernization Act (SB 1652), which became effective immediately. The Illinois General

 

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Assembly also passed House Bill 3036 (the Trailer Bill), which modifies and supplements SB 1652. The Governor signed the Trailer Bill into law on December 30, 2011. The combined legislation (EIMA) provides for substantial capital investment over a ten-year period to modernize Illinois’ electric utility infrastructure and for greater certainty related to the recovery of costs by a utility through a pre-established distribution formula rate tariff. Under the terms of EIMA, ComEd’s target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. In addition, ComEd will make contributions to fund customer assistance programs and for a new Science and Technology Innovation Trust fund. The legislation also contains a provision for the IPA to conduct procurement events for energy and REC requirements for the June 2013 through December 2017 period. In order to protect consumers, EIMA contains several restrictions and potential criteria for early termination, ending ComEd’s investment commitment and the performance-based formula rates.

 

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The ICC will review ComEd’s rate filing to evaluate the prudence and reasonableness of the costs and issue its order in a shortened proceeding. This rate will take effect 30 days after the ICC order, which must be issued by May 31, 2012. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Electric Distribution Rate Cases. The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). On September 30, 2010, the Court issued a decision in those appeals. That decision ruled 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). ComEd’s Petition for Leave to Appeal to the Illinois Supreme Court was denied on March 30, 2011. The ICC has initiated a proceeding on remand. ComEd expects that the ICC will issue a final order in early 2012. ComEd filed testimony that no refunds should be required in this proceeding and, in the event of any refund, the maximum refund should be $30 million. On November 10, 2011, the ALJ issued a proposed order in the remand proceeding agreeing with ComEd that the ICC does not have the legal authority to order a refund; a refund may only be ordered by a court. The ALJ also concluded that, to the extent that a court orders a refund, it should be in the amount of $37 million, including interest. As of December 31, 2011, ComEd has recognized for accounting purposes its best estimate of any refund obligation, subject to reconciliation when the ICC issues a final order. ComEd does not believe any of its other riders are affected by the Court’s ruling.

 

On May 24, 2011, the ICC issued an order in ComEd’s 2010 electric distribution rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd’s annual delivery services revenue requirement and a 10.5% rate of return on common equity. The order allowed ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets, which is reflected as a reduction in operating and maintenance expense and income tax expense for the year ended December 31, 2011. The order has been appealed to the Court by several parties. ComEd cannot predict the results of these appeals. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electric distribution rate cases.

 

Procurement-Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation,

 

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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.

 

Continuous Power Interruption. 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 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 2011, 2010 and 2009 it had any interruptions that have triggered this damage liability or reimbursement requirement.

 

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable under provisions of the Illinois Public Utilities Act that could require damage compensation to customers in connection with the July 11, 2011 storm system that affected more than 900,000 customers in ComEd’s service territory, as well as five other storm systems that affected ComEd’s customers during June and July 2011. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non-consequential damages, and the local governments in which those customers are located could seek recovery of emergency and contingency expenses. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

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 2 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2012 is $1,330 million, which includes RTEP projects and infrastructure modernization resulting from EIMA. 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 areas 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.

 

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PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 4.0 million. PECO provides electric distribution service in an area of approximately 1,900 square miles, with a population of approximately 3.9 million, including approximately 1.5 million in the City of Philadelphia. PECO provides natural gas distribution service in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.6 million customers and natural gas to approximately 494,000 customers.

 

PECO has the necessary authorizations to provide regulated electric and natural gas distribution 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; however, 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 July 22, 2011 and was 8,983 MW; its highest peak load during winter months 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.

 

Retail Electric Services

 

PECO’s retail electric sales and distribution service 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 that 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. As of 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 adjustments at least quarterly 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 retail transmission and distribution service remains regulated under the Competition Act. At December 31, 2011, there were 59 alternative EGSs serving PECO customers. At December 31, 2011, the number of retail customers purchasing energy from an alternative EGS was 387,628, representing approximately 25% of total retail customers. Retail deliveries purchased from EGSs represented approximately 57% of PECO’s retail kWh sales for the year ended December 31, 2011. This represents a significant increase from prior years due to the expiration of electric generation rate caps that were lower than market prices during the transition period. Customers that choose an alternative EGS are not subject to rates for PECO’s electric supply procurement costs and retail transmission service charges. PECO presents on customer bills its electric supply Price to Compare, which is updated quarterly, to assist customers with the evaluation of offers from alternative EGSs.

 

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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 customers in its service territory and charges a regulated rate for distribution service.

 

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.

 

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 contracts executed in accordance with its current PAPUC-approved DSP Program. PECO has entered into contracts with PAPUC-approved bidders as part of its six competitive procurements conducted since June 2009 for its default electric supply beginning 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. PECO will conduct three additional competitive procurements for electric supply for all customer classes during the term of its current DSP Program, which expires on May 31, 2013.

 

On January 13, 2012, PECO filed its second Default Service Plan for approval with the PAPUC, which outlined how PECO will purchase electric supply for default service customers from June 1, 2013 through May 31, 2015. The plan proposed to procure electric supply through a combination of one-year and two-year fixed full requirements contracts, reduce the amount of time between when the energy is purchased and when it is provided to customers and complete an annual, rather than quarterly, reconciliation of costs for actual versus forecasted energy use. The plan also proposed several new programs to continue PECO’s support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. Hearings on the filing will be held in the summer of 2012 with a PAPUC ruling expected in mid-October 2012.

 

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. Also, in April 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA of 2009. 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 by 2013, accelerate universal deployment of more than 1.6 million smart meters by 2020 and increase smart grid investments to approximately $100 million through 2013. In total, through 2020, PECO plans 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. PECO’s approved four-year EE&C plan totals approximately $328 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,

 

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governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. In July 2011, PECO filed a petition to make adjustments to its EE&C Plan. The filing noted that PECO has exceeded the 1% energy use reduction target required by May 31, 2011 in accordance with Act 129; the adjustments, which were approved by the PAPUC on August 18, 2011, will allow PECO to meet its May 31, 2013 targets for energy use and energy demand reductions, while remaining within its approved plan budget.

 

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

 

Natural Gas

 

PECO’s natural gas sales and distribution service revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a significant 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 2011, 40% of PECO’s current total yearly throughput was provided by natural gas suppliers other than PECO, of which, 34% was for commercial and industrial customers participating in PECO’s High Volume Transportation Program and 6% was for residential and small commercial customers participating in PECO’s Low Volume Transportation Choice Program. PECO provides distribution service, billing, metering, installation, maintenance and emergency response services at regulated rates to all customers in PECO’s service territory.

 

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, which became effective in natural gas distribution rates on January 1, 2011.

 

Procurement Proceedings. PECO’s natural gas supply is purchased from a number of suppliers primarily under long-term firm transportation contracts for terms of up to two years in accordance with its annual PAPUC PGC settlement. 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 2011-2012 heating season planned supplies.

 

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 electric transmission and electric and natural gas distribution facilities to ensure the adequate capacity, reliability and efficiency of its system. PECO, as a transmission facilities owner, has various construction commitments under PJM’s RTEP as discussed in Note 2 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2012 is $436 million, which includes capital expenditures related to the smart meter program and SGIG project net of DOE expected reimbursements.

 

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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.

 

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. Beginning January 1, 2011, PECO default service customers are charged for retail transmission services through a rider designed to recover PECO’s PJM transmission network service charges and RTEP charges on a full and current basis in accordance with the 2010 electric distribution rate case settlement.

 

The transmission rate in the PJM Open Access Transmission Tariff under which PECO incurs costs to serve its default service customers and earns revenue as a transmission facility owner is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for wholesale transmission service.

 

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

 

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Employees

 

As of December 31, 2011, Exelon and its subsidiaries had 19,267 employees in the following companies, of which 8,567 or 44% were covered by collective bargaining agreements (CBAs):

 

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

Generation

     1,697        150        1,813        3,660        9,586  

ComEd

     3,561        —           —           3,561        5,769  

PECO

     —           1,237        —           1,237        2,418  

Other (d)

     82        —           27        109        1,494  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     5,340        1,387        1,840        8,567        19,267  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) A separate CBA between ComEd and IBEW Local 15, ratified on November 20, 2009, covers approximately 42 employees in ComEd’s System Services Group.
(b) 1,237 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 150 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 between 2013 and 2015, except for the agreements at Braidwood, Byron and TMI, which expire in 2012. Additionally, during 2009, a 5-year agreement was reached with Oyster Creek Nuclear Local 1289, which will expire in 2015. In 2010, a 3-year agreement was negotiated with New England ENEH, UWUA Local 369, which will expire in 2014, and covers 10 employees. In 2011, four 3-year agreements were reached at Braidwood, Dresden, LaSalle and Quad Cities.
(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 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 and PECO.

 

Water

 

Under the 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

 

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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 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.

 

Environmental Remediation

 

ComEd’s 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 2012 at Exelon for compliance with environmental remediation is expected to total $32 million, consisting of $26 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.

 

Generation’s environmental liabilities primarily arise from contamination at current or former generation facilities. As of December 31, 2011, Generation has established an appropriate accrual to comply with environmental remediation requirements which includes an accrual for contamination attributable to low level radioactive residues at a storage and reprocessing facility named Latty Avenue near St. Louis, Missouri formerly owned by Cotter Corporation, a former ComEd subsidiary.

 

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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 owned 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 CSAPR, the regulation of hazardous air pollutants from coal- and oil-fired electric generating facilities under the Mercury and Air Toxics (MATS) rule, 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 2011. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, hydroelectric, wind and solar photovoltaic), 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 5% 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, 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 2011 United Nations Framework Convention on Climate Change (COP 17) Conference in Durban, South Africa, a

 

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package of decisions was adopted that initiate another commitment phase for the Kyoto Protocol and initiating a new round of discussions with the objective of establishing a successor agreement by 2015 that would commence beginning in 2020. These decisions build on the agreements reached in the 2009 Copenhagen Accord, including the United States agreeing 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.

 

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. It is uncertain when any mandatory programs to reduce GHG emissions would be established 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 to procure emission allowances or credits.

 

The U.S. EPA is addressing the issue of GHG emissions regulation for new stationary sources through its proposed New Source Performance Standard under the existing provisions of the Clean Air Act. Such proposed regulation has the potential to cause Exelon to incur material costs of compliance for GHG emissions from stationary sources.

 

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 intensity 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 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.

 

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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 retirement of fossil units, Cromby Units 1 and 2 and Eddystone Unit 1 in 2011 and the planned retirement of 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. 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 strategy 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 adopt such legislation in the future.

 

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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, 2011, 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 was effective for PECO on January 1, 2011, following the expiration of PECO’s transition period. During 2011, PECO was 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 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 comply with these requirements, PECO entered into agreements with varying terms with accepted bidders, including Generation, to purchase non-solar Tier I, solar Tier 1 and Tier II AECs. PECO also purchases AECs through its DSP Program full requirement contracts.

 

Similar to ComEd and PECO, Generation’s retail electric business must source a portion of the electric load it serves in Illinois and Pennsylvania 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 and Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Executive Officers of the Registrants as of February 9, 2012

 

Name

  Age   

Position

  

Period

Rowe, John W.

  66    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

 

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Name

  Age   

Position

  

Period

Crane, Christopher M.

  53    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.

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

O’Brien, Denis P.

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

Gillis, Ruth Ann M.

  57    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

Von Hoene Jr., William A.

  58    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.

  48    Senior Vice President and Chief Financial Officer, Exelon; Chief Financial Officer, Generation    2008 - Present
     Treasurer, Exelon, Generation and Exelon Business Services Company; Assistant Treasurer, ComEd; Vice President, Exelon Business Services Company    2011 - Present
     Senior Vice President and Corporate Controller, Exelon    2005 - 2008

Cornew, Kenneth W.

  46    Senior Vice President, Exelon; President, Power Team    2008 - Present
     Senior Vice President, Trading and Origination, Power Team    2007 - 2008

Dominguez, Joseph

  48    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

 

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Name

  Age   

Position

  

Period

Pramaggiore, Anne R.

  53    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.

  56    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

DesParte, Duane M.

  48    Vice President and Corporate Controller, Exelon    2008 - Present
     Vice President, Finance, Exelon Business Services Company    2007 - 2008

 

Generation

 

Name

  Age   

Position

  

Period

Rowe, John W.

  66    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.

  53    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.

  52    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.

  46    Senior Vice President, Exelon; President, Power Team    2008 - Present
     Senior Vice President, Trading and Origination, Power Team    2007 - 2008

Pacilio, Michael J.

  51    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

 

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Name

  Age     

Position

  

Period

Garg, Sunil

    45      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

Dominguez, Joseph

    48      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.

    48      Senior Vice President and Chief Financial Officer, Exelon; Chief Financial Officer, Generation    2008 - Present
     Treasurer, Exelon, Generation and Exelon Business Services Company; Assistant Treasurer, ComEd; Vice President, Exelon Business Services Company    2011 - Present
     Senior Vice President and Corporate Controller, Exelon    2005 - 2008

Galvanoni, Matthew R.

    39      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

 

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ComEd

 

Name

  Age     

Position

  

Period

Clark, Frank M.

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

Pramaggiore, Anne R.

    53      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.

    63      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

Donnelly, Terence R.

    51      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

Trpik Jr., Joseph R.

    42      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

Marquez Jr., Fidel

    50      Senior Vice President, Customer Operations, ComEd    2009 - Present
     Vice President of External Affairs and Large Customer Services, ComEd    2007 - 2009

O’Neill, Thomas S.

    49      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

 

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Name

  Age     

Position

  

Period

Anthony, J. Tyler

    47      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

Waden, Kevin J.

    40      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

 

PECO

 

Name

  Age     

Position

  

Period

Rowe, John W.

    66       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. CornEd    2009 - Present
     Director, PECO    2005 - Present

O’Brien, Denis P.

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

Adams, Craig L.

    59      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.

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

Bonney, Paul R.

    53      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.

    65      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.

    40      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

 

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ITEM 1A. RISK FACTORS

 

Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond the 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 known material risks that 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 by a Registrant to be material that may adversely affect its performance or financial condition in the future.

 

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 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 receive, 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.

 

   

Risks Related to the Pending Merger with Constellation. As a result of the merger agreement announced with Constellation on April 28, 2011, Exelon is subject to additional risks.

 

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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 has increased natural gas supply and reserves, placing further downward pressure on natural gas prices and could reduce Generation’s revenue, and, therefore, adversely affecting the its financial condition, results of operations and cash flows. In addition, further delay or elimination of EPA air quality regulations will tend to place downward pressure on market prices and could reduce Generation’s revenue, and, therefore, adversely affect its financial condition, results of operations and cash flows. Further, in the event that alternative generation resources, such as wind 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, and could also result in an impairment of such plants.

 

The market price for electricity is also affected by changes in the demand for electricity. Worse 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 in 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.

 

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In addition, Generation’s retail sales subject it 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 to meet those obligations. 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 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 or changes to Social Security or Medicare eligibility requirements may also increase the costs and 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 in the United States or abroad 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

 

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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 Registrants have exposure to worldwide financial markets, including Europe. The ongoing European debt crisis has contributed to the instability in global credit markets. Further disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2011, approximately 35%, or $2.7 billion, of the Registrants’ available credit facilities were with European banks. The credit facilities include $7.7 billion in aggregate total commitments of which $6.8 billion was available as of December 31, 2011. There were no borrowings under the Registrants’ credit facilities as of December 31, 2011. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.

 

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.

 

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 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 its hedging arrangements 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 the applicable hedge, (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

 

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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 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 its 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.

 

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.

 

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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.

 

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 the tests administered by FERC, Generation 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 address the changes in the wholesale power markets.

 

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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 2012. 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, 2011, Exelon’s potential cash outflow, including tax and interest, could be as much as $860 million, of which $550 million would be paid by ComEd and the remainder by Exelon. If the deferral were successfully challenged by the IRS, Exelon’s results of operations could also be negatively impacted due to increased interest expense of up to $260 million, net of tax, of which $200 million would be recorded at ComEd and the remainder at Exelon. 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.

 

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 and PECO’s current procurement plans include purchasing power through contracted suppliers and in the spot market. 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

 

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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, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage 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 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 59%, 49%, 58% and 64% of total assets for Exelon, Generation, ComEd and PECO, respectively, as of December 31, 2011. 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, 2011 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

 

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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. A fully successful IRS challenge to Exelon’s and ComEd’s like-kind exchange income tax position or adverse regulatory actions such as early termination of EIMA 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 OPERATIONS—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 by Generation in energy generation and by ComEd and PECO in transmission and distribution infrastructure projects. The Registrants’ 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. BUSINESS 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 or 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 contracts and would be adversely affected by negative events impacting these contracts, including the non-performance or a significant change in the creditworthiness of ComEd. A default by ComEd under these contracts 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

 

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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 retail customers switching to or from 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 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 the ability of ComEd and PECO 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 affecting 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 a 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, therefore, are facing calls for some form of re-regulation or some other means of

 

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reducing wholesale market prices. As the energy markets continue to mature, if the number of wholesale market power participants entering procurement proceedings shrinks, this could 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. Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.

 

Approximately 75% 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 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 state laws designed to reduce wholesale prices artificially below competitive levels, such as the New Jersey Capacity Legislation. See Note 2 of the Combined Notes to Consolidated Financial Statements for further details related to the New Jersey Capacity Legislation.

 

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 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 most recent submission seeking reauthorization to sell at market-based rates was accepted by FERC on June 22, 2011 for the PJM region.

 

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was enacted into law on July 21, 2010. Its primary objective is to eliminate from the financial system the systemic risk that Congress believed was in part the cause of the financial crisis that unfolded during the Fall of 2008. Dodd-Frank ushers in a brand new regulatory regime applicable to the over-the-counter (OTC) market for swaps. Generation relies on the OTC swaps markets as part of its program to hedge the price risk associated with its generation portfolio. 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 through a self-identification process, based on the meaning of those terms established in the final rules. If Generation is deemed a swap dealer, it will be required to register with the CFTC and execute most bilateral OTC derivative transactions through an exchange or central clearinghouse. This requirement could cause Generation to commit substantial additional capital to support the business and to cover increases in its collateral costs associated with margin requirements of the major exchanges such as the NYMEX. Generation would also face increased reporting and record-keeping requirements, would have to abide by CFTC-specified business conduct standards, and adhere to position limits in a potentially broad range of energy commodities.

 

Even if Generation is not deemed a swap dealer, it will still face additional regulatory obligations under Dodd-Frank, including some reporting requirements, clearing some additional transactions that it would otherwise enter into over-the-counter, and having to adhere to position limits. More fundamentally, however, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swaps market to decreases substantially. As Generation’s hedging program relies heavily on its ability to access the current bilateral OTC swaps market, the new rules could impede Generation’s ability to meet its hedge targets in a cost-effective manner. Generation continues to monitor and participate in the rulemaking process. Generation cannot predict the ultimate outcome that Dodd-Frank will have on its results of operations, cash flows or financial position.

 

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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 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 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 are 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) of the Clean Water Act, 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. Pursuant to discussions with the NJDEP regarding the application of Section 316(b) to Oyster Creek, Generation agreed to 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.

 

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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.

 

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 in 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 their respective service areas 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 the recently enacted EIMA and appeals in connection with ComEd’s 2007 and 2010 Illinois electric distribution rate cases.

 

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.

 

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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 and investments in the future as a result of PJM’s RTEP and NERC compliance requirements. (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.

 

ComEd and PECO as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments may require ComEd and PECO to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. 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, 2011, 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 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, 2011, 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, 2011, the extraordinary charge could have been as much as $ 610 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 $3.0 billion and $32 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.

 

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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 ITEM 1. BUSINESS “Global Climate Change” and Note 18 of the Combined Notes to Consolidated Financial Statements.

 

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 are 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.

 

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.

 

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Natural disasters, war, acts and threats of terrorism, 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)

 

Generation’s fleet of nuclear power plants and ComEd’s and PECO’s distribution and transmission infrastructures could be impacted by natural disasters, such as seismic activity, more frequent and more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. 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. An example of such an event was the 9.0 magnitude earthquake and ensuing tsunami experienced by Japan on March 11, 2011, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. Also, in 2011, the Mid-Atlantic region of the United States experienced a 5.8 magnitude earthquake and flooding associated with hurricane Irene and tropical storm Lee. These events increase the risk to Generation that the NRC or other regulatory or legislative bodies may change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological aspects. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general may adversely affect the Registrants’ operations and their ability to raise capital.

 

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, the Registrants face a risk that their operations would be direct targets of, or indirect casualties of, an act of terror. Any retaliatory military strikes or sustained military campaign may affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also may affect the Registrants’ 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.

 

The Registrants 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.

 

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.

 

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Nuclear refueling outages. Refueling outages are planned to occur once every 18 to 24 months and are currently planned to 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, 2011, 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.

 

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.

 

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As an example, prior to the Fukushima Daiichi accident on March 11, 2011, the NRC had been evaluating seismic risk. After the Fukushima Daiichi accident, the NRC’s focus on seismic risk intensified. As part of the NRC Near-Term Task Force (Task Force) review and evaluation of the Fukushima Daiichi accident, the Task Force recommended that plant operators conduct seismic reevaluations. In January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the Task Force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation, Executive Overview for a more detailed discussion of the Task Force Recommendations.

 

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. In addition, Generation may not achieve the anticipated results under its series of planned power uprates across its nuclear fleet. 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 operator 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 generating plants or failure of transmission lines, could effect 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 or abroad, 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.

 

Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance. 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. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional discussion of nuclear insurance.

 

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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 would be 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 making 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 licenses 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, including information systems, 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 or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in ComEd or PECO’s service territory fail to perform as intended or are not successfully integrated with billing and other information systems, ComEd and PECO’s financial condition, results of operations, and cash flows could be adversely affected.

 

The aforementioned 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, and those damages could be material to ComEd’s results of operations and cash flows.

 

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 operation of the generation fleet and/or reliability of the transmission and distribution system or subject

 

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them to financial harm associated with theft or inappropriate release of certain types of information. ComEd and PECO’s deployment of smart meters throughout their service territories may increase the risk of damage from an intentional disruption of the system by third parties. 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. In addition, new or updated security regulations would require changes in current measures taken by the Registrants and could adversely affect their results of operations, cash flows and financial position.

 

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 intended to fit their strategic objectives and improve their financial performance. It is possible that FERC, state public utility commissions or others 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 the 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.

 

Risks Related to the Pending Merger with Constellation

 

Because the market price of shares of Exelon common stock will fluctuate and the exchange ratio will not be adjusted to reflect such fluctuations, the merger consideration at the date of the closing may vary significantly from the date the merger agreement was executed.

 

Upon completion of the merger, each outstanding share of Constellation common stock will be converted into the right to receive 0.930 of a share of Exelon common stock. The number of shares of Exelon common stock to be issued pursuant to the merger agreement for each share of Constellation common stock will not change to reflect changes in the market price of Exelon or Constellation common stock. The market price of Exelon common stock at the time of completion of the merger may vary significantly from the market prices of Exelon common stock on the date the merger agreement was executed.

 

In addition, Exelon might not complete the merger until a significant period of time has passed after the respective special shareholder meetings to approve the merger occurred. Because Exelon will not adjust the exchange ratio to reflect any changes in the market value of Exelon common stock or Constellation common stock, the market value of the Exelon common stock issued in connection with the merger and the Constellation common stock surrendered in connection with the merger may be higher or lower than the values of those shares on earlier dates. Stock price changes may result from market assessment of the likelihood that the merger will be completed, changes in the business, operations or prospects of Exelon or Constellation prior to or following the merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of Exelon and Constellation. Neither Exelon nor Constellation is permitted to terminate the merger agreement solely because of changes in the market price of either company’s common stock.

 

The combined company’s assets, liabilities or results of operations could be adversely affected by unknown or unexpected events, conditions or actions that occur prior to the closing of the merger.

 

The Constellation assets, liabilities, business, financial condition, cash flows, operating results and prospects to be acquired or assumed by Exelon by reason of the merger could be adversely affected

 

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before or after the merger closing as a result of previously unknown events or conditions occurring or existing before the merger closing. Adverse changes in Constellation’s business or operations could occur or arise as a result of actions by Constellation, legal or regulatory developments including the emergence or unfavorable resolution of pre-acquisition loss contingencies, deteriorating general business, market, industry or economic conditions, and other factors both within and beyond the control of Constellation. A significant decline in the value of Constellation assets to be acquired by Exelon or a significant increase in Constellation liabilities to be assumed by Exelon could adversely affect the combined company’s future business, financial condition, cash flows, operating results and prospects.

 

The merger agreement contains provisions that limit each of Exelon’s and Constellation’s ability to pursue alternatives to the merger, which could discourage a potential acquirer of either Constellation or Exelon from making an alternative transaction proposal and, in certain circumstances, could require Exelon or Constellation to pay to the other a significant termination fee.

 

Under the merger agreement, Exelon and Constellation are restricted, subject to limited exceptions, from entering into alternative transactions in lieu of the merger. In general, unless and until the merger agreement is terminated, both Exelon and Constellation are restricted from, among other things, soliciting, initiating, knowingly encouraging or facilitating a competing acquisition proposal from any person. Each of the Exelon board of directors and the Constellation board of directors is limited in its ability to change its recommendation with respect to the merger-related proposals. Exelon or Constellation may terminate the merger agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the non-solicitation provisions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Exelon or Constellation from considering or proposing such an acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the consideration proposed to be received or realized in the merger, or might result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon.

 

Exelon and Constellation will be subject to various uncertainties and contractual restrictions while the merger is pending that may cause disruption and could adversely affect their financial results.

 

Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on Exelon and/or Constellation. These uncertainties may impair Exelon’s and/or Constellation’s ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company, and could cause customers, suppliers and others who deal with Exelon or Constellation to seek to change existing business relationships with Exelon or Constellation. The pursuit of the merger and the preparation for the integration may also place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect Exelon’s and/or Constellation’s financial results.

 

In addition, the merger agreement restricts each of Exelon and Constellation, without the other’s consent, from making certain acquisitions and taking other specified actions while the merger is

 

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pending. These restrictions may prevent Exelon and/or Constellation from pursuing otherwise attractive business opportunities and making other changes to their respective businesses prior to completion of the merger or termination of the merger agreement.

 

If completed, the merger may not achieve its anticipated results, and Exelon and Constellation may be unable to integrate their operations in the manner expected.

 

Exelon and Constellation entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation can be integrated in an efficient, effective and timely manner.

 

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and prospects.

 

The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.

 

Exelon currently anticipates that the merger will be accretive to earnings per share in 2013, which is expected to be the first full year following completion of the merger. This expectation is based on preliminary estimates that are subject to change. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.

 

Exelon may record goodwill that could become impaired and adversely affect its operating results.

 

Accounting standards in the United States require that one party to the merger be identified as the acquirer. In accordance with these standards, the merger will be accounted for as an acquisition of Constellation common stock by Exelon and will follow the acquisition method of accounting for business combinations. The assets and liabilities of Constellation will be consolidated with those of Exelon. The excess of the purchase price over the fair values of Constellation’s assets and liabilities, if any, will be recorded as goodwill.

 

The amount of goodwill, which could be material, will be allocated to the appropriate reporting units of the combined company. Exelon is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material charge that would have a material impact on Exelon’s future operating results and consolidated balance sheet.

 

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Pending litigation against Exelon and Constellation could result in an injunction preventing the completion of the merger or a judgment resulting in the payment of damages in the event the merger is completed and may adversely affect the combined company’s business, financial condition or results of operations and cash flows following the merger.

 

Twelve purported class action lawsuits were filed against Constellation, each member of Constellation’s board of directors, Exelon and Bolt Acquisition Corporation, a Maryland corporation and a wholly owned subsidiary of Exelon, in connection with the merger. Among other things, the lawsuits sought injunctive relief that would have prevented completion of the merger in accordance with the terms of the merger agreement. The parties to the litigation have reached a settlement that remains subject to court approval. If the settlement is not approved by the court, these lawsuits could prevent or delay completion of the merger and result in substantial costs to Exelon and Constellation, including any costs associated with the indemnification of directors and officers. Plaintiffs may file additional lawsuits against Exelon, Constellation and/or the directors and officers of either company in connection with the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company’s business, financial condition, results of operations and cash flows.

 

The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.

 

Completion of the merger is conditioned upon the receipt of consents, orders, approvals or clearances, to the extent required, from the FERC, the NRC, the FCC, and the public utility commissions or similar entities in certain states in which the companies operate, including the Maryland Public Service Commission. The merger is also subject to review by the DOJ Antitrust Division, under the HSR Act, and the expiration or earlier termination of the waiting period (and any extension of the waiting period) applicable to the merger is a condition to closing the merger. As of February 9, 2012, the merger remains subject to the approval of the NRC, FERC and the Maryland Public Service Commission, which may impose conditions for approval beyond those already proposed by Exelon and Constellation. The shareholders of Exelon and Constellation approved the proposals required to complete the merger at the special meetings of the shareholders before any or all of the required regulatory approvals have been obtained and before all conditions to such approvals, if any, are known.

 

As a result, Exelon and Constellation may subsequently agree to conditions without seeking further shareholder approval, even if such conditions could have an adverse effect on Exelon, Constellation or the combined company.

 

Exelon and Constellation cannot provide assurance that all required regulatory consents or approvals will be obtained or that these consents or approvals will not contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the merger. The merger agreement generally permits each party to terminate the merger agreement if the final terms of any of the required regulatory consents or approvals require (1) any action that involves divesting, holding separate or otherwise transferring control over any nuclear or hydroelectric or pumped-storage generation assets of the parties or any of their respective subsidiaries or affiliates; or (2) any action (including any action that involves divesting, holding separate or otherwise transferring control over base-load capacity), without including those actions proposed by the parties’ mutually agreed-upon analysis of mitigation to address the increased market concentration resulting from the merger and the concessions announced by the parties in the press release announcing the merger agreement, which would, individually or in the aggregate, reasonably be expected to have a material adverse effect on either party. Any substantial delay in obtaining satisfactory approvals, receipt of proceeds from

 

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required divestitures in an amount substantially lower than anticipated or the imposition of any terms or conditions in connection with such approvals could cause a material reduction in the expected benefits of the merger. If any such delays or conditions are serious enough, the parties may decide to abandon the merger.

 

Exelon cannot assure that it will be able to continue paying dividends at the current rate.

 

Exelon currently expects to pay dividends in an amount consistent with the dividend policy of Exelon in effect prior to the completion of the merger. However, there is no assurance that Exelon shareholders will receive the same dividends following the merger for reasons that may include any of the following factors:

 

   

Exelon may not have enough cash to pay such dividends due to changes in Exelon’s cash requirements, capital spending plans, financing agreements, cash flow or financial position;

 

   

decisions on whether, when and in which amounts to make any future distributions will remain at all times entirely at the discretion of the Exelon board of directors, which reserves the right to change Exelon’s dividend practices at any time and for any reason;

 

   

the amount of dividends that Exelon may distribute to its shareholders is subject to restrictions under Pennsylvania law; and

 

   

Exelon may not receive dividend payments from its subsidiaries in the same level that it has historically. The ability of Exelon’s subsidiaries to make dividend payments to it is subject to factors similar to those listed above.

 

Exelon’s shareholders have no contractual or other legal right to dividends that have not been declared.

 

If completed, the merger may adversely affect the combined company’s ability to attract and retain key employees.

 

Current and prospective Exelon and Constellation employees may experience uncertainty about their future roles at the combined company following the completion of the merger. In addition, current and prospective Exelon and Constellation employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect the combined company’s ability to attract and retain key management and other personnel.

 

Failure to complete the merger could negatively affect the share prices and the future businesses and financial results of Exelon and Constellation.

 

Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the merger is not completed, the ongoing businesses of Exelon or Constellation may be adversely affected and Exelon and Constellation will be subject to several risks, including:

 

   

having to pay certain significant costs relating to the merger without receiving the benefits of the merger, including, in certain circumstances, a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon;

 

   

Exelon and Constellation will have been subject to certain restrictions on the conduct of their businesses, which may have prevented them from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and

 

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the share price of Exelon or Constellation may decline to the extent that the current market prices reflect an assumption by the market that the merger will be completed.

 

Exelon and Constellation may incur unexpected transaction fees and merger-related costs in connection with the merger.

 

Exelon and Constellation expect to incur a number of non-recurring expenses, totalling approximately $150 million, associated with completing the merger, as well as expenses related to combining the operations of the two companies. The combined company may incur additional unanticipated costs in the integration of the businesses of Exelon and Constellation. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.

 

Current Exelon shareholders and Constellation stockholders will have a reduced ownership and voting interest after the merger.

 

Exelon will issue or reserve for issuance approximately 201.9 million shares of Exelon common stock to Constellation stockholders in the merger (including shares of Exelon common stock issuable pursuant to Constellation stock options and other equity-based awards). Based on the number of shares of common stock of Exelon and Constellation outstanding on March 31, 2011, the record date for the two companies’ special meetings of shareholders, upon the completion of the merger, current Exelon shareholders and former Constellation stockholders would own approximately 78% and 22% of the outstanding shares of Exelon common stock, respectively, immediately following the consummation of the merger.

 

Exelon shareholders and Constellation stockholders currently have the right to vote for their respective directors and on other matters affecting their company. When the merger occurs, each Constellation stockholder who receives shares of Exelon common stock will become a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage ownership of Constellation.

 

Correspondingly, each Exelon shareholder will remain a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage of Exelon prior to the merger. As a result of these reduced ownership percentages, Exelon shareholders will have less voting power in the combined company than they now have with respect to Exelon, and former Constellation stockholders will have less voting power in the combined company than they now have with respect to Constellation.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

Exelon, Generation, ComEd and PECO

 

None.

 

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ITEM 2. PROPERTIES

 

Generation

 

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2011:

 

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         2,348  

Byron

     Byron, IL         2           Uranium         Base-load         2,323  

Clinton

     Clinton, IL         1           Uranium         Base-load         1,067  

Dresden

     Morris, IL         2           Uranium         Base-load         1,753  

LaSalle

     Seneca, IL         2           Uranium         Base-load         2,316  

Limerick

     Limerick Twp., PA         2           Uranium         Base-load         2,312  

Oyster Creek

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

Peach Bottom

     Peach Bottom Twp., PA         2        50        Uranium         Base-load         1,150 (f) 

Quad Cities

     Cordova, IL         2        75        Uranium         Base-load         1,380 (f) 

Salem

     Hancock’s Bridge, NJ         2        42.59        Uranium         Base-load         1,004 (f) 

Three Mile Island

     Londonderry Twp, PA         1           Uranium         Base-load         837  
                 

 

 

 
                    17,115  

Fossil (Steam Turbines)(g)

                 

Conemaugh

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

Eddystone 3, 4

     Eddystone, PA         2           Oil/Gas         Intermediate         760  

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  

Wolf Hollow 1, 2

     Granbury, TX         2           Gas         Intermediate         425  

Wolf Hollow 3

     Granbury, TX         1           Gas         Intermediate         280  

Wyman

     Yarmouth, ME         1        5.89        Oil         Intermediate         36 (f) 
                 

 

 

 
                    4,446  

Fossil (Combustion Turbines)

                 

Chester

     Chester, PA         3           Oil         Peaking         39  

Croydon

     Bristol Twp., PA         8            Oil         Peaking         391   

Delaware

     Philadelphia, PA         4           Oil         Peaking         56  

Eddystone

     Eddystone, PA         4           Oil         Peaking         60  

Falls

     Falls Twp., PA         3           Oil         Peaking         51  

Framingham

     Framingham, MA         3           Oil         Peaking         28  

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  

Richmond

     Philadelphia, PA         2           Oil         Peaking         98  

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  
                 

 

 

 
                    1,437  

 

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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 (Internal Combustion/Diesel)

                 

Conemaugh

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

Keystone

     Shelocta, PA         4        20.99        Oil         Peaking         2 (f) 

Schuylkill

     Philadelphia, PA         1           Oil         Peaking         3  
                 

 

 

 
                    7  

Hydroelectric and Other Renewables

                 

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        99        Wind         Base-load         2 (f) 

CP Windfarm

     Faribault Co., MN         2           Wind         Base-load         4  

Echo 1

     Umatilla Co., OR         21        99        Wind         Base-load         34 (f) 

Echo 2

     Morrow Co., OR         10           Wind         Base-load         20  

Echo 3

     Morrow Co., OR         6        99        Wind         Base-load         10 (f) 

Exelon Wind 1

     Hansford Co., TX         8           Wind         Base-load         10  

Exelon Wind 2

     Hansford Co., TX         8           Wind         Base-load         10  

Exelon Wind 3

     Hansford Co., TX         8           Wind         Base-load         10  

Exelon Wind 4

     Hansford Co., TX         38           Wind         Base-load         80  

Exelon Wind 5

     Sherman Co., TX         8           Wind         Base-load         10  

Exelon Wind 6

     Sherman Co., TX         8           Wind         Base-load         10  

Exelon Wind 7

     Moore Co., TX         8           Wind         Base-load         10  

Exelon Wind 8

     Moore Co., TX         8           Wind         Base-load         10  

Exelon Wind 9

     Moore Co., TX         8           Wind         Base-load         10  

Exelon Wind 10

     Moore Co., TX         8           Wind         Base-load         10  

Exelon Wind 11

     Moore Co., TX         8           Wind         Base-load         10  

Ewington

     Jackson Co., MN         10        99        Wind         Base-load         20 (f) 

Fairless Hills

     Falls Twp, PA         2           Landfill Gas         Peaking         60  

Greensburg

     Kiowa Co., KS         10           Wind         Base-load         13  

Harvest

     Huron Co., MI         32           Wind         Base-load         53  

High Plains

     Moore Co., TX         8        99.5        Wind         Base-load         10 (f) 

Loess Hills

     Atchinson Co., MO         4           Wind         Base-load         5  

Marshall

     Lyon Co., MN         9        98-99         Wind         Base-load         19 (f)

Michigan Wind 1

     Bingham Twp., MI         46           Wind         Base-load         69  

Michigan Wind 2

     Bingham Twp., MI         50           Wind         Base-load         90  

Mountain Home

     Elmore Co., ID         20           Wind         Base-load         40  

Muddy Run

     Lancaster, PA         8           Hydroelectric         Intermediate         1,070  

Norgaard

     Lincoln Co., MN         7        99        Wind         Base-load         9 (f) 

Pennsbury

     Falls Twp., PA         2           Landfill Gas         Peaking         6  

Threemile Canyon

     Morrow Co., OR         6           Wind         Base-load         10  

 

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Station

  

Location

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

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

Tuana Springs

     Twin Falls Co., ID         8           Wind         Base-load         17  

Wolf

     Nobles Co., MN         5        99        Wind         Base-load         6 (f) 
                 

 

 

 
                    2,539  
                 

 

 

 

Total

                    25,544  
                 

 

 

 

 

(a) 100%, unless otherwise indicated.
(b) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(c) For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. For wind stations, reflects the name plate capacity.
(d) All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.
(e) Generation has agreed to permanently cease generation operation at Oyster Creek by December 31, 2019. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.
(f) Net generation capacity is stated at proportionate ownership share.
(g) Excludes Eddystone Generating Station (Eddystone) Unit 2, which is operating pursuant to a reliability-must-run (RMR) agreement with PJM through May 31, 2012. Eddystone Unit 2 will cease operations upon the end of the RMR period. See Note 14 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

 

Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. Business—Generation. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results of operations.

 

ComEd

 

ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

 

Transmission and Distribution

 

ComEd’s higher voltage electric transmission lines owned and in service at December 31, 2011 were as follows:

 

Voltage (Volts)

 

Circuit Miles

765,000

  90

345,000

  2,642

138,000

  2,237

 

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ComEd’s electric distribution system includes 35,569 circuit miles of overhead lines and 30,408 circuit miles of underground lines.

 

First Mortgage and Insurance

 

The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First Mortgage Bonds are issued.

 

ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ComEd.

 

PECO

 

PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

 

Transmission and Distribution

 

PECO’s high voltage electric transmission lines owned and in service at December 31, 2011 were as follows:

 

Voltage (Volts)

 

Circuit Miles

500,000

  188(a)

230,000

  541

138,000

  156

69,000

  200

 

(a) In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey.

 

PECO’s electric distribution system includes 12,972 circuit miles of overhead lines and 8,851 circuit miles of underground lines.

 

Gas

 

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2011:

 

     Pipeline Miles  

Transportation

     31  

Distribution

     6,732  

Service piping

     4,533  
  

 

 

 

Total

     11,296  
  

 

 

 

 

PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 157 mmcf/day and a propane-air plant located in

 

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Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25 mmcf/day. In addition, PECO owns 32 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.

 

First Mortgage and Insurance

 

The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.

 

PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of PECO.

 

Exelon

 

Security Measures

 

The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.

 

ITEM 3. LEGAL PROCEEDINGS

 

Exelon, Generation, ComEd and PECO

 

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Exelon, Generation, ComEd and PECO

 

Not Applicable to the Registrants.

 

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PART II

 

(Dollars in millions except per share data, unless otherwise noted)

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Exelon

 

Exelon’s common stock is listed on the New York Stock Exchange. As of January 31, 2012, there were 663,640,976 shares of common stock outstanding and approximately 125,092 record holders of common stock.

 

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:

 

     2011      2010  
     Fourth
Quarter
     Third
Quarter
     Second
Quarter
     First
Quarter
     Fourth
Quarter
     Third
Quarter
     Second
Quarter
     First
Quarter
 

High price

   $ 45.45      $ 45.27      $ 42.89      $ 43.58      $ 44.49      $ 43.32      $ 45.10      $ 49.88  

Low price

     39.93        39.51        39.53        39.06        39.05        37.63        37.24        42.97  

Close

     43.37        42.61        42.84        41.24        41.64        42.58        37.97        43.81  

Dividends

     0.525        0.525        0.525        0.525        0.525        0.525        0.525        0.525  

 

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Stock Performance Graph

 

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index for the period 2007 through 2011.

 

This performance chart assumes:

 

   

$100 invested on December 31, 2006 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

 

   

All dividends are reinvested.

 

LOGO

 

Generation

 

As of January 31, 2012, Exelon indirectly held the entire membership interest in Generation.

 

ComEd

 

As of January 31, 2012, there were 127,016,529 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2012, in addition to Exelon, there were 240 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

 

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PECO

 

As of January 31, 2012, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.

 

Exelon, Generation, ComEd and PECO

 

Dividends

 

Under applicable Federal law, Generation, ComEd and PECO can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd or PECO may limit the dividends that these companies can distribute to Exelon.

 

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

 

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

 

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. At December 31, 2011, such capital was $2.9 billion and amounted to about 34 times the liquidating value of the outstanding preferred securities of $87 million.

 

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

 

At December 31, 2011, Exelon had retained earnings of $10,055 million, including Generation’s undistributed earnings of $4,232 million, ComEd’s retained earnings of $447 million consisting of retained earnings appropriated for future dividends of $2,086 million, partially offset by $1,639 million of unappropriated retained deficits, and PECO’s retained earnings of $559 million.

 

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The following table sets forth Exelon’s quarterly cash dividends per share paid during 2011 and 2010:

 

     2011      2010  

(per share)

  

4th
Quarter

    

3rd
Quarter

    

2nd
Quarter

    

1st
Quarter

    

4th
Quarter

    

3rd
Quarter

    

2nd
Quarter

    

1st
Quarter

 

Exelon

   $ 0.525      $ 0.525      $ 0.525      $ 0.525      $ 0.525      $ 0.525      $ 0.525      $ 0.525  

 

The following table sets forth Generation’s quarterly distributions and ComEd’s and PECO’s quarterly common dividend payments:

 

     2011      2010  

(in millions)

   4th
Quarter
     3rd
Quarter
     2nd
Quarter
     1st
Quarter
     4th
Quarter
     3rd
Quarter
     2nd
Quarter
     1st
Quarter
 

Generation

   $ 111      $ 61      $ —         $ —         $ 885      $ 206      $ 156      $ 261  

ComEd

     75        75        75        75        85        75        75        75  

PECO

     80        84        73        111        46        63        51        64  

 

First Quarter 2012 Dividend. On October 25, 2011, the Exelon Board of Directors declared a first quarter 2012 regular quarterly dividend of $0.525 per share on Exelon’s common stock payable on March 9, 2012, to shareholders of record of Exelon at the end of the day on February 15, 2012.

 

Second Quarter 2012 Dividend. In addition, on January 24, 2012, the Exelon Board of Directors declared a second quarter 2012 regular quarterly dividend of $0.525 per share on Exelon’s common stock contingent on the pending merger with Constellation. If the effective date of the merger is after May 15, 2012, the Board of Directors declared a regular quarterly dividend of $0.525 per share on Exelon’s common stock, payable on June 8, 2012, to shareholders of record of Exelon at the end of the day on May 15, 2012.

 

If the effective date of the merger is on or before May 15, 2012, shareholders will receive two separate dividend payments totaling $0.525 per share:

 

   

The first of the dividend payments will be pro-rated, with shareholders of record as of the end of day before the effective date of the merger receiving $0.00583 per share per day for the period from and including February 16, 2012, the day after the record date for the previous dividend, through and including the day before the effective date of the merger. This portion of the dividend will be paid within 30 days after the effective date of the merger.

 

   

The second of the dividend payments will also be pro-rated, with all Exelon shareholders, including the former Constellation shareholders, of record at the end of the day on May 15, 2012, receiving $0.00583 per share per day for the period from and including the effective date of the merger through and including May 15, 2012. This portion of the dividend will be paid on June 8, 2012.

 

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ITEM 6. SELECTED FINANCIAL DATA

 

Exelon

 

The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

     For the Years Ended December 31,  

(In millions, except per share data)

   2011      2010      2009      2008      2007  

Statement of Operations data:

              

Operating revenues

   $ 18,924      $ 18,644      $ 17,318      $ 18,859      $ 18,916  

Operating income

     4,480        4,726        4,750        5,299        4,668  

Income from continuing operations

   $ 2,495      $ 2,563      $ 2,706      $ 2,717      $ 2,726  

Income from discontinued operations

     —           —           1        20        10  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income

   $ 2,495      $ 2,563      $ 2,707      $ 2,737      $ 2,736  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Earnings per average common share (diluted):

              

Income from continuing operations

   $ 3.75      $ 3.87      $ 4.09      $ 4.10      $ 4.03  

Income from discontinued operations

     —           —           —           0.03        0.02  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income

   $ 3.75      $ 3.87      $ 4.09      $ 4.13      $ 4.05  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Dividends per common share

   $ 2.10      $ 2.10      $ 2.10      $ 2.03      $ 1.76  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Average shares of common stock outstanding— diluted

     665        663        662        662        676  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     December 31,  

(In millions)

   2011      2010      2009      2008 (a)      2007 (a)(b)  

Balance Sheet data:

              

Current assets

   $ 5,489      $ 6,398      $ 5,441      $ 5,130      $ 4,416  

Property, plant and equipment, net

     32,570        29,941        27,341        25,813        24,153  

Noncurrent regulatory assets

     4,839        4,140        4,872        5,940        5,133  

Goodwill

     2,625        2,625        2,625        2,625        2,625  

Other deferred debits and other assets

     9,569        9,136        8,901        8,038        8,760  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 55,092      $ 52,240      $ 49,180      $ 47,546      $ 45,087  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 4,989      $ 4,240      $ 4,238      $ 3,811      $ 5,466  

Long-term debt, including long-term debt to financing trusts

     12,189        12,004        11,385        12,592        11,965  

Noncurrent regulatory liabilities

     3,771        3,555        3,492        2,520        3,301  

Other deferred credits and other liabilities

     19,668        18,791        17,338        17,489        14,131  

Preferred securities of subsidiary

     87        87        87        87        87  

Noncontrolling interest

     3        3        —           —           —     

Shareholders’ equity

     14,385        13,560        12,640        11,047        10,137  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and shareholders’ equity

   $ 55,092      $ 52,240      $ 49,180      $ 47,546      $ 45,087  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Exelon retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform to the current year presentation.
(b) Exelon retrospectively reclassified certain assets and liabilities in accordance with the applicable authoritative guidance for offsetting amounts related to qualifying derivative contracts.

 

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Generation

 

The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

     For the Years Ended December 31,  

(In millions)

   2011      2010      2009      2008      2007  

Statement of Operations data:

              

Operating revenues

   $ 10,308      $ 10,025      $ 9,703      $ 10,754      $ 10,749  

Operating income

     2,876        3,046        3,295        3,994        3,392  

Income from continuing operations

   $ 1,771      $ 1,972      $ 2,122      $ 2,258      $ 2,025  

Income from discontinued operations

     —           —           —           20        4  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income

   $ 1,771      $ 1,972      $ 2,122      $ 2,278      $ 2,029  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     December 31,  

(In millions)

   2011      2010      2009      2008 (a)      2007 (a)(b)  

Balance Sheet data:

              

Current assets

   $ 3,204      $ 3,087      $ 3,360      $ 3,486      $ 2,160  

Property, plant and equipment, net

     13,475        11,662        9,809        8,907        8,043  

Other deferred debits and other assets

     10,754        9,785        9,237        7,691        8,044  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 27,433      $ 24,534      $ 22,406      $ 20,084      $ 18,247  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 2,144      $ 1,843      $ 2,262      $ 2,168      $ 1,917  

Long-term debt

     3,674        3,676        2,967        2,502        2,513  

Other deferred credits and other liabilities

     12,907        11,838        10,385        8,848        9,447  

Noncontrolling interest

     5        5        2        1        1  

Member’s equity

     8,703        7,172        6,790        6,565        4,369  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and member’s equity

   $ 27,433      $ 24,534      $ 22,406      $ 20,084      $ 18,247  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation.
(b) Generation reclassified certain assets and liabilities in accordance with the applicable authoritative guidance for offsetting amounts related to qualifying derivative contracts.

 

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ComEd

 

The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

     For the Years Ended December 31,  

(In millions)

   2011      2010      2009      2008      2007  

Statement of Operations data:

              

Operating revenues

   $ 6,056      $ 6,204      $ 5,774      $ 6,136      $ 6,104  

Operating income

     982        1,056        843        667        512  

Net income

     416        337        374        201        165  
     December 31,  

(In millions)

   2011      2010      2009      2008      2007  

Balance Sheet data:

              

Current assets

   $ 2,106      $ 2,151      $ 1,579      $ 1,309      $ 1,241  

Property, plant and equipment, net

     13,121        12,578        12,125        11,655        11,127  

Goodwill

     2,625        2,625        2,625        2,625        2,625  

Noncurrent regulatory assets

     796        947        1,096        858        503  

Other deferred debits and other assets

     4,005        3,351        3,272        2,790        3,880  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 22,653      $ 21,652      $ 20,697      $ 19,237      $ 19,376  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 1,946      $ 2,134      $ 1,597      $ 1,153      $ 1,712  

Long-term debt, including long-term debt to financing trusts

     5,421        4,860        4,704        4,915        4,384  

Noncurrent regulatory liabilities

     3,167        3,137        3,145        2,440        3,447  

Other deferred credits and other liabilities

     5,082        4,611        4,369        3,994        3,305  

Shareholders’ equity

     7,037        6,910        6,882        6,735        6,528  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and shareholders’ equity

   $ 22,653      $ 21,652      $ 20,697      $ 19,237      $ 19,376  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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PECO

 

The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

     For the Years Ended December 31,  

(In millions)

   2011      2010      2009      2008      2007  

Statement of Operations data:

              

Operating revenues

   $ 3,720      $ 5,519      $ 5,311      $ 5,567      $ 5,613  

Operating income

     655        661        697        699        947