10-K 1 d10k.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, 2009

 

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.  x

 

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, 2009, was as follows:

 

Exelon Corporation Common Stock, without par value

   $ 33,730,940,743

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 29, 2010 was as follows:

 

Exelon Corporation Common Stock, without par value

   659,895,066

Exelon Generation Company, LLC

   not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

   127,016,519

PECO Energy Company Common Stock, without par value

   170,478,507

 

Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2010 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

   iv

FILING FORMAT

   vii

FORWARD-LOOKING STATEMENTS

   vii

WHERE TO FIND MORE INFORMATION

   vii

PART I

     
ITEM 1.   

BUSINESS

   1
  

General

   1
  

Exelon Generation Company, LLC

   1
  

Commonwealth Edison Company

   13
  

PECO Energy Company

   15
  

Employees

   19
  

Environmental Regulation

   20
  

Executive Officers of the Registrants

   25
ITEM 1A.   

RISK FACTORS

   29
ITEM 1B.   

UNRESOLVED STAFF COMMENTS

   50
ITEM 2.   

PROPERTIES

   50
  

Exelon Generation Company, LLC

   50
  

Commonwealth Edison Company

   52
  

PECO Energy Company

   52
ITEM 3.   

LEGAL PROCEEDINGS

   54
  

Exelon Corporation

   54
  

Exelon Generation Company, LLC

   54
  

Commonwealth Edison Company

   54
  

PECO Energy Company

   54
ITEM 4.   

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   54

PART II

     
ITEM 5.   

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

   55
ITEM 6.   

SELECTED FINANCIAL DATA

   59
  

Exelon Corporation

   59
  

Exelon Generation Company, LLC

   60
  

Commonwealth Edison Company

   61
  

PECO Energy Company

   62
ITEM 7.   

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

   63
  

Exelon Corporation

   63
  

General

   63
  

Executive Overview

   63
  

Critical Accounting Policies and Estimates

   69
  

Results of Operations

   81
  

Liquidity and Capital Resources

   106
  

Exelon Generation Company, LLC

   146
  

Commonwealth Edison Company

   148
  

PECO Energy Company

   150
ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   131
  

Exelon Corporation

   131
  

Exelon Generation Company, LLC

   147
  

Commonwealth Edison Company

   149
  

PECO Energy Company

   151

 

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     Page No.
ITEM 8.   

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   152
  

Exelon Corporation

   160
  

Exelon Generation Company, LLC

   166
  

Commonwealth Edison Company

   172
  

PECO Energy Company

   178
  

Combined Notes to Consolidated Financial Statements

   184
  

1. Significant Accounting Policies

   184
  

2. Regulatory Issues

   200
  

3. Accounts Receivable

   212
  

4. Property, Plant and Equipment

   212
  

5. Jointly Owned Electric Utility Plant

   216
  

6. Intangible Assets

   217
  

7. Fair Value of Financial Assets and Liabilities

   219
  

8. Derivative Financial Instruments

   234
  

9. Debt and Credit Agreements

   247
  

10. Income Taxes

   254
  

11. Asset Retirement Obligations

   264
  

12. Spent Nuclear Fuel Obligation

   270
  

13. Retirement Benefits

   271
  

14. Corporate Restructuring and Plant Retirements

   285
  

15. Preferred Securities

   287
  

16. Common Stock

   288
  

17. Earnings Per Share and Equity

   296
  

18. Commitments and Contingencies

   296
  

19. Supplemental Financial Information

   316
  

20. Segment Information

   331
  

21. Related Party Transactions

   333
  

22. Quarterly Data

   341
ITEM 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   343
ITEM 9A.   

CONTROLS AND PROCEDURES

   343
  

Exelon Corporation

   343
  

Exelon Generation Company, LLC

   343
  

Commonwealth Edison Company

   343
  

PECO Energy Company

   343
ITEM 9B.   

OTHER INFORMATION

   343
  

Exelon Corporation

   343
  

Exelon Generation Company, LLC

   343
  

Commonwealth Edison Company

   343
  

PECO Energy Company

   343

 

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     Page No.

PART III

     
ITEM 10.   

DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

   344
  

Exelon Corporation

   344
  

Exelon Generation Company, LLC

   344
  

Commonwealth Edison Company

   345
  

PECO Energy Company

   347
ITEM 11.   

EXECUTIVE COMPENSATION

   350
ITEM 12.   

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

   409
  

Exelon Corporation

   409
  

Exelon Generation Company, LLC

   409
  

Commonwealth Edison Company

   411
  

PECO Energy Company

   409
ITEM 13.   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

   413
ITEM 14.   

PRINCIPAL ACCOUNTING FEES AND SERVICES

   414
  

Exelon Corporation

   414
  

Exelon Generation Company, LLC

   415
  

Commonwealth Edison Company

   415
  

PECO Energy Company

   416

PART IV

     

ITEM 15.

  

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   417

SIGNATURES

   442
  

Exelon Corporation

   442
  

Exelon Generation Company, LLC

   443
  

Commonwealth Edison Company

   444
  

PECO Energy Company

   445

CERTIFICATION EXHIBITS

  

 

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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

Enterprises

   Exelon Enterprises Company, LLC

Ventures

   Exelon Ventures Company, LLC

AmerGen

   AmerGen Energy Company, LLC

ComEd Funding

   ComEd Funding LLC

CTFT

   ComEd Transitional Funding Trust

PEC L.P.

   PECO Energy Capital, L.P.

PECO Trust III

   PECO Capital Trust III

PECO Trust IV

   PECO Energy Capital Trust IV

PETT

   PECO Energy Transition Trust

Registrants

   Exelon, Generation, ComEd, and PECO, collectively

Other Terms and Abbreviations

1998 restructuring settlement

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

Act 129

   Pennsylvania Act 129 of 2008

AEC

   Alternative Energy Credit

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

ARRA of 2009

   American Recovery and Reinvestment Act of 2009

ASLB

   Atomic Safety Licensing Board

Block Contracts

   Forward Purchase Energy Block Contracts

CAIR

   Clear Air Interstate Rule

CAMR

   Federal Clear Air Mercury Rule

CERCLA

   Comprehensive Environmental Response, Compensation and Liability Act of 1980

Competition Act

   Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996

CTC

   Competitive Transition Charge

DOE

   U.S. Department of Energy

DOJ

   United States Department of Justice

DSP Program

   Default Service Provider Program

EPA

   Environmental Protection Agency

ERCOT

   Electric Reliability Council of Texas

ERISA

   Employee Retirement Income Security Act

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

 

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GAAP

   Generally Accepted Accounting Principles in the United States

GHG

   Greenhouse Gas

GWh

   Gigawatt Hour

HB 80

   Pennsylvania House Bill No. 80

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

IPA

   Illinois Power Agency

IRC

   Internal Revenue Code

IRS

   Internal Revenue Service

ISO

   Independent System Operator

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

NAV

   Net Asset Value

NDT

   Nuclear Decommissioning Trust

NEIL

   Nuclear Electric Insurance Limited

NERC

   North American Electric Reliability Corporation

NJDEP

   New Jersey Department of Environmental Protection

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

PA DEP

   Pennsylvania Department of Environmental Protection

PAPUC

   Pennsylvania Public Utility Commission

PGC

   Purchased Gas Cost Clause

PJM

   PJM Interconnection, LLC

POLR

   Provider of Last Resort

PPA

   Power Purchase Agreement

PCCA

   Pennsylvania Climate Change Act

PRP

   Potentially Responsible Parties

PSEG

   Public Service Enterprise Group Incorporated

PUHCA

   Public Utility Holding Company Act of 1935

PURTA

   Pennsylvania Public Realty Tax Act

RCRA

   Resource Conservation and Recovery Act

 

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REC

   Renewable Energy Credit

RFP

   Request for Proposal

RPM

   PJM Reliability Pricing Model

RPS

   Renewable Energy Portfolio Standards

RGGI

   Regional Greenhouse Gas Initiative

RMC

   Risk Management Committee

RTEP

   Regional Transmission Expansion Plan

RTO

   Regional Transmission Organization

S&P

   Standard & Poor’s Ratings Services

SEC

   United States Securities and Exchange Commission

SECA

   Seams Elimination Charge/Cost Adjustments/Assignment

SERP

   Supplemental Employee Retirement Plan

SFC

   Supplier Forward Contract

SILO

   Sale-In, Lease-Out

SNF

   Spent Nuclear Fuel

SSCM

   Simplified Service Cost Method

TEG

   Termoelectrica del Golfo

TEP

   Termoelectrica Penoles

VIE

   Variable Interest Entity

 

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FILING FORMAT

 

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

 

FORWARD-LOOKING STATEMENTS

 

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a Registrant include those factors discussed herein, including those factors with respect to such Registrant discussed in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, (c) ITEM 8. Financial Statements and Supplementary Data: Note 18 and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

 

WHERE TO FIND MORE INFORMATION

 

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

 

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

 

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PART I

 

ITEM 1. BUSINESS

 

General

 

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

 

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

 

Generation

 

Generation’s business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and its competitive retail supply operations.

 

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

 

ComEd

 

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

 

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

 

PECO

 

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

 

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

 

Generation

 

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MW. Generation combines its large generation fleet with an experienced wholesale energy marketing operation and a competitive retail supply operation.

 

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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 that is operated consistently at high capacity factors position it well to succeed in competitive energy markets.

 

At December 31, 2009, Generation owned generation assets with an aggregate net capacity of 24,850 MW, including 17,009 MW of nuclear capacity. Generation controlled another 6,153 MW of capacity through long-term contracts.

 

Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, draws upon Generation’s energy generation portfolio and logistical expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts, including a full requirements PPA with PECO, which expires on December 31, 2010, and procurement contracts with ComEd and PECO covering a portion of their current and future electricity requirements. In addition, Power Team markets energy in the wholesale, bilateral and spot markets.

 

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

 

Generation is a public utility under the Federal Power Act, which gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of the utilities and set cost-based rates should the FERC find the market-based rates are not just and reasonable. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction are required to file rate schedules with FERC with respect to wholesale sales and transmission of electricity. Open-Access Transmission tariffs established under FERC regulation give Generation transmission access that enables Generation to participate in competitive wholesale markets. 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 and matters. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC. The promulgation of these standards has created the risk of fines and penalties being imposed by NERC and/or FERC for noncompliance. Exelon has a company-wide NERC Reliability Standards Compliance Program, which includes an employee training program, independent audits, and self assessments.

 

For a number of years, RTOs, such as PJM, have been formed in a number of regions to provide transmission service across multiple transmission systems. To date, PJM, the MISO, ISO-NE and Southwest Power Pool, have been approved as RTOs. The intended benefits of establishing these entities include 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.

 

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

 

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Generating Resources

 

At December 31, 2009, the generating resources of Generation consisted of the following:

 

Type of Capacity

   MW

Owned generation assets (a)

  

Nuclear

   17,009

Fossil (b)

   6,189

Hydroelectric/Renewable

   1,652
    

Owned generation assets

   24,850

Long-term contracts (c)

   6,153
    

Total generating resources

   31,003
    

 

(a) See “Fuel” for sources of fuels used in electric generation.
(b) Includes 933 MW of capacity related to Units 1 and 2 at Cromby Generating Station and Units 1 and 2 Eddystone Generating station which were approved for retirement by the Exelon Board of Directors on December 1, 2009. See Plant Retirements section for further details.
(c) Long-term contracts range in duration up to 21 years.

 

The owned and contracted generating resources of Generation are located in the United States in the Midwest region, which is comprised of Illinois (approximately 46% of capacity), the Mid-Atlantic region, which is comprised of Pennsylvania, New Jersey, Maryland and West Virginia (approximately 37% of capacity), the Southern region, which is comprised of Texas, Georgia and Oklahoma (approximately 16% of capacity), and the New England region, which is comprised of Massachusetts and Maine (approximately 1% of capacity).

 

Nuclear Facilities

 

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units and 17,009 MW of capacity. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2009 and 2008, electric supply (in GWh) generated from the nuclear generating facilities was 81% and 79%, respectively, of Generation’s total electric supply, which also includes fossil and hydroelectric generation and electric supply purchased for resale. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of Generation’s electric supply sources.

 

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

 

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

 

During 2009 and 2008, the nuclear generating facilities operated by Generation achieved a 93.6% and 93.9% capacity factor, respectively. Generation aggressively manages its scheduled refueling

 

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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 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. In addition, 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. 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 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.

 

NRC reactor oversight results, as of December 31, 2009, show that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band, with the exception of one indicator for Oyster Creek, which the NRC considers to be in an acceptable performance band.

 

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 TMI Unit 1. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

 

Station

   Unit    In-Service
Date (a)
   Current License
Expiration

Braidwood (b)

   1    1988    2026
   2    1988    2027

Byron (b)

   1    1985    2024
   2    1987    2026

Clinton (c)

   1    1987    2026

Dresden (b, d)

   2    1970    2029
   3    1971    2031

LaSalle (b)

   1    1984    2022
   2    1984    2023

Limerick (e)

   1    1986    2024
   2    1990    2029

Oyster Creek (c, f)

   1    1969    2029

Peach Bottom (d, g)

   2    1974    2033
   3    1974    2034

Quad Cities (b, h)

   1    1973    2032
   2    1973    2032

Salem (d)

   1    1977    2016
   2    1981    2020

Three Mile Island (c, i)

   1    1974    2034

 

(a) Denotes year in which nuclear unit began commercial operations.
(b) Stations previously owned by ComEd.

 

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(c) Stations previously owned by AmerGen.
(d) On October 28, 2004, the NRC issued the renewed operating licenses for Dresden Unit 2 and Unit 3.
(e) Stations previously owned by PECO.
(f) On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek Unit 1.
(g) On May 7, 2003, the NRC issued the renewed operating licenses for Peach Bottom Unit 2 and Unit 3.
(h) On October 28, 2004, the NRC issued the renewed operating licenses for Quad Cities Unit 1 and Unit 2.
(i) On October 22, 2009, the NRC issued the renewed operating license for Three Mile Island Unit 1.

 

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

 

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

 

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

 

Nuclear Uprates. On June 12, 2009, in connection with the 38-MW increase in capacity at Generation’s Quad Cities nuclear plant in Illinois, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total expected investment of approximately $3.5 billion, as measured in current costs. 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 one quarter of the planned uprates, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Dresden, LaSalle and Quad Cities plants in Illinois. The remainder of uprate MW will come from additional projects across Generation’s nuclear fleet beginning in 2010 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are to be accomplished through 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.

 

New Site Development. Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. Generation has been exploring the development 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. As a result of uncertainties in the domestic economy, the limited availability of Federal loan guarantees and related economic considerations, Generation announced on June 30, 2009, that it will seek an Early Site Permit (ESP) for its proposed new nuclear plant site rather than a construction and operating license as originally planned and filed with the NRC during 2008. The change in licensing strategy allows Generation to continue with some aspects of site evaluation and

 

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approvals while deferring a decision on construction and technology choices for up to 20 years. The ESP application is on schedule to be submitted to the NRC by March 31, 2010. Additionally, Generation continues to hold options for acquiring the land. Among the various conditions that must be resolved before any formal decision is made to build a new nuclear plant by Generation are the granting of an ESP; significant progress to resolve questions around the short-term interim and long-term permanent storage, as well as potential future recycling, of SNF; broad public acceptance of a new nuclear plant; and assurances that a new plant can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, including the availability of sufficient financing, production and other potential tax credits, and other key economic factors. In June 2009, Exelon and Generation approved an additional $30 million of expenditures on the project, bringing total authorized spending on the project to $130 million. Amounts spent on the project through December 31, 2009 have been expensed and total approximately $97 million. The development phase of the project is expected to extend into 2010, with approval of funding beyond the $130 million commitment subject to management review and Exelon board approval.

 

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 is developing dry cask storage facilities, as necessary, to support operations.

 

As of December 31, 2009, Generation had approximately 52,300 SNF assemblies (12,600 tons) stored on site in SNF pools or dry cask storage. 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 period, and through decommissioning, until the DOE completes removing SNF from the sites. The following table describes the current status of Generation’s SNF storage facilities.

 

Site

   Date for loss of full core reserve (a)

Braidwood

   2013

Byron

   2011

Clinton

   2018

Dresden

   Dry cask storage in operation

LaSalle

   2010

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

   2011

Three Mile Island (b)

   2025

 

(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 12 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

 

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

 

Generation is currently utilizing on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW 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. Due to the limited availability of LLRW disposal facilities, Generation continues to anticipate difficulties in shipping LLRW off of its sites and 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 protection provisions. See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for details.

 

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

 

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, 7 and 11 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.

 

Dresden Unit 1, Peach Bottom Unit 1 and Zion (Zion Station), a two-unit nuclear generation station, 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. SNF at Zion Station is currently stored in on-site storage pools. Generation’s estimated liability to decommission Dresden Unit 1, Peach Bottom Unit 1 and Zion Station was $780 million at December 31, 2009. As of December 31, 2009, NDT funds set aside to pay for these obligations were $1,188 million.

 

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

 

If the various closing conditions under the Asset Sale Agreement are satisfied and the transaction is completed, Generation will transfer to ZionSolutions substantially all of the assets (other than land)

 

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associated with Zion Station, including assets held in NDTs (approximately $888 million as of December 31, 2009). In consideration for Generation’s transfer of those assets, ZionSolutions will assume decommissioning and other liabilities associated with Zion Station. For accounting purposes, based on agreements signed to date, the decommissioning funds are expected to continue to be recorded on Generation’s balance sheet and the transferred decommissioning obligation is expected to be replaced with a payable to ZionSolutions on Generation’s balance sheet. ZionSolutions will take possession and control of the land associated with Zion Station pursuant to a Lease Agreement with Generation, to be executed at the closing. Under the Lease Agreement, ZionSolutions will commit to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement will be $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce any potential risk of default by EnergySolutions or ZionSolutions, EnergySolutions is required to provide a $200 million letter of credit to be used to fund decommissioning costs in case of a shortfall of decommissioning funds following specified failures of performance. EnergySolutions has also provided a performance guarantee and will enter into other agreements that will provide rights and remedies for Generation in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station. However, if the resources of EnergySolutions Inc. and its subsidiaries are inadequate to complete required decommissioning work, Generation may be required to complete the work at its own expense.

 

ZionSolutions and Generation will also enter into a Put Option Agreement pursuant to which ZionSolutions will have the option to transfer the remaining Zion Station assets and any associated liabilities back to Generation upon completion of all required decommissioning and other work at Zion Station. The purchase price payable under the Put Option Agreement is $1.00 plus the assumption of associated liabilities.

 

Completion of the transactions contemplated by the Asset Sale Agreement is subject to the satisfaction of a number of closing conditions, including the receipt of a private letter ruling from the IRS, and the approval of the license transfer from the NRC. On July 14, 2008, the IRS issued a private letter ruling indicating that the proposed transfer of the decommissioning funds would be treated as non-taxable to both Generation and EnergySolutions, and the NRC approved the license transfer request on May 4, 2009. Prior to completion of the transaction, EnergySolutions must submit a budget that demonstrates that the required work can be completed on schedule for the amount of funds held in decommissioning trusts. On October 14, 2008, EnergySolutions announced that it intended to defer the transfer of the Zion Station assets until after the financial markets stabilize and EnergySolutions reaffirms that there is sufficient value in the Zion decommissioning trust funds to ensure the success of the Zion early decommissioning project. During 2009, NDT fund balances associated with Zion Station improved to $888 million as of December 31, 2009 compared to $749 million as of December 31, 2008. Pursuant to their agreement, EnergySolutions and Generation have until December 31, 2011, to close the transaction, although the parties have rights to withdraw from the transaction before that date. Generation believes that accelerated decommissioning will make the land available for other uses earlier than originally thought possible, and can be completed cost effectively for the amounts that were collected from ratepayers and deposited into the NDT funds for Zion Station.

 

Fossil, Hydroelectric and Renewable Facilities

 

Generation operates various fossil and hydroelectric facilities and maintains ownership interests in several other facilities including LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2009 and 2008, electric supply (in GWh) generated from owned fossil and hydroelectric

 

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generating facilities was 6% 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.

 

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

 

Plant Retirements. On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station Unit 1 and Unit 2 and Eddystone Generating Station Unit 1 and Unit 2. On January 5, 2010, PJM notified Exelon that based upon its preliminary analysis, the retirement of one or more of the Cromby and Eddystone units may result in reliability impacts to the transmission system. On February 1, 2010, Generation notified PJM that to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date during the period of construction of the necessary transmission upgrades, provided that Exelon receives the required environmental permits and adequate cost-based compensation. For more information regarding the proposed plant retirements, see Note 14 of the Combined Notes to Consolidated Financial Statements.

 

City Solar. On April 22, 2009, Exelon announced that it is developing a 10-MW solar power plant in Chicago, Illinois. The new plant supports Exelon’s strategy to reduce carbon emissions associated with fossil-fueled electricity generation. As of December 31, 2009, the project is approximately 82% complete and has commenced commercial operations. The project is expected to be completed by February 28, 2010. The estimated project cost is $64 million. As of December 31, 2009, total costs incurred were approximately $51 million.

 

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

 

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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, 2009:

 

Seller

   Location    Expiration    Capacity (MW)

Kincaid Generation, LLC

   Kincaid, Illinois    2013    1,108

Tenaska Georgia Partners, LP (a)

   Franklin, Georgia    2030    942

Tenaska Frontier, Ltd

   Shiro, Texas    2020    830

Green Country Energy, LLC (b)

   Jenks, Oklahoma    2022    795

Elwood Energy, LLC

   Elwood, Illinois    2012    775

Lincoln Generating Facility, LLC

   Manhattan, Illinois    2011    664

Wolf Hollow

   Granbury, Texas    2023    350

Old Trail Windfarm, LLC

   McLean, Illinois    2026    198

Others (c)

   Various    2011 to 2028    491
          

Total

         6,153
          

 

(a) Commencing June 1, 2010 and lasting for 20 years, Generation has agreed to sell its rights to 942 MW of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a PPA with Georgia Power, a subsidiary of Southern Company.
(b) Commencing June 1, 2012 and lasting for 10 years, Generation has agreed to sell its rights to 520 MW, or approximately two-thirds, of capacity, energy, and ancillary services supplied from its existing long-term contract with Green Country Energy, LLC through a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power Company, Inc.
(c) Includes long-term capacity contracts with seven counterparties.

 

Illinois Settlement Agreement

 

In July 2007, following extensive discussions with legislative leaders in Illinois, Generation, ComEd and other utilities and generators in Illinois reached an agreement (Illinois Settlement) with various parties concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation reflecting the Illinois Settlement (Illinois Settlement Legislation) was signed into law in August 2007. Generation and ComEd committed to contributing $811 million to rate relief programs over the four-year period and partial funding for the IPA. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, $307.5 million for rate relief programs for customers of other Illinois utilities and $4.5 million for partially funding operations of the IPA. Through December 31, 2009, Generation has recognized net costs from its contributions of $727 million in the Statement of Operations of its total commitment of $747 million. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Illinois Settlement Legislation.

 

Fuel

 

The following table shows sources of electric supply in GWh for 2009 and estimated for 2010:

 

     Source of Electric Supply (a)
         2009            2010 (Est.)    

Nuclear units

   139,670    139,725

Purchases—non-trading portfolio

   23,206    21,025

Fossil and hydroelectric units

   10,189    11,674
         

Total supply

   173,065    172,424
         

 

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

 

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

 

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

 

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

 

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

 

Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates and Note 8 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 growth 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. Power Team 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 has also purchased 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.

 

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Power Team 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 the ComEd swap which runs into 2013. However, except for the ComEd swap arrangement described below, Generation is exposed to relatively greater commodity price risk beyond 2010 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, 2009, the percentage of expected generation hedged was 91% – 94%, 69% – 72%, and 37% – 40% for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts, including sales to ComEd and PECO to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities. Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for only a small portion of Power Team’s efforts.

 

At December 31, 2009, Generation’s short and long-term commitments relating to the purchase and sale of energy and capacity from and to unaffiliated utilities and others were as follows:

 

(in millions)

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

2010

   $ 305    $ 91    $ 1,307    $ 10

2011

     291      49      1,046      9

2012

     274      22      568      9

2013

     151      —        238      6

2014

     145      —        120      —  

Thereafter

     1,105      —        761      —  
                           

Total

   $ 2,271    $ 162    $ 4,040    $ 34
                           

 

(a) Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2009. Expected payments include certain capacity charges which are conditional on 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.

 

On January 1, 2007, Generation began supplying a portion of ComEd’s load through staggered SFCs resulting from an ICC-approved “reverse auction” in 2006. Approximately 35% of the contracted supply from the 2006 auction was awarded to Generation. Under the terms of the auction, one-third of the contracted load expired in May 2008, another one-third expired in May 2009 and the remaining load will expire in May 2010. For the period from June 2008 to May 2009, Generation was awarded standard block energy purchase contracts with ComEd through an ICC-approved RFP. ComEd purchased the remainder of its energy load for this period on the spot market and through the existing SFCs. In addition, in order to fulfill a requirement of the Illinois Settlement to mitigate the price risk inherent in this plan, ComEd locked in a portion of the energy price through a five-year financial swap contract with Generation.

 

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The Illinois Settlement Legislation established a new competitive process, effective June 2009, for energy procurement to be managed by the IPA, with oversight by the ICC. The IPA’s plan for ComEd’s procurement of energy from June 2009 through May 2010 was approved by the ICC in January 2009. Under the IPA’s plan, Generation will continue to supply a portion of ComEd’s energy load. See Notes 2 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

 

Generation has a PPA with PECO under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010. Generation supplies electricity to PECO from its portfolio of generation assets, PPAs and other market sources. Subsequent to 2010, PECO will procure all of its electricity from market sources, including Generation. See PECO—Retail Electric Services, Pennsylvania Transition-Related and Regulatory Matters for additional information regarding PECO’s competitive, full-requirements energy-supply procurement process after 2010.

 

Capital Expenditures

 

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2010 are as follows:

 

(in millions)

    

Production plant

   $ 1,126

Nuclear fuel (a)

     848
      

Total

   $ 1,974
      

 

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

 

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, for which Exelon has formed a company-wide NERC Reliability Standards Compliance Program.

 

ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of 8 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 2010 to 2066. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

 

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

 

Retail Electric Services

 

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

 

As of December 31, 2009, several competitive electric generation suppliers have been granted approval by the ICC to serve retail electricity customers in Illinois. There are currently a minimal number of residential customers being served by alternate suppliers. At December 31, 2009, approximately 53,400 retail customers (primarily commercial and industrial customers), representing approximately 52% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier. Customers who receive electricity from a competitive electric generation supplier continue to pay a delivery charge to ComEd.

 

Under Illinois law, ComEd is required to deliver electricity to all customers. ComEd’s obligation to provide fixed-price full service electric service including generation supply service, which is referred to as POLR obligations, varies by customer size. ComEd’s obligation to provide such service to residential customers and other small customers with demands of under 100 kW continues for all customers who do not or cannot choose a competitive electric generation supplier or who choose to return to the utility after taking service from a competitive electric generation supplier. ComEd does not have a fixed-price full service obligation to many of its largest customers with demands of 400 kW or greater, as this group of customers has previously been declared competitive. ComEd has full service obligations for customers with demands of 100-400 kW through May 2010. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

 

Delivery Service Rate Cases. In August 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007. During 2006, the ICC issued various orders associated with this case, which resulted in a total annual rate increase of $83 million effective January 2007. ComEd and various other parties appealed the rate order to the courts. In September 2009, the Illinois Appellate Court affirmed the ICC’s order and denied the appeals. Several parties have asked the Appellate Court to rehear some of the rate design issues addressed in the opinion. There is no set time in which the court must act.

 

In October 2007, ComEd filed a rate case with the ICC for approval to increase its delivery service revenue requirement by approximately $360 million. The ICC issued an order in the rate case approving a $274 million increase in the annual revenue requirement, which became effective in September 2008. ComEd and several other parties have filed appeals of the rate order with the courts. ComEd cannot predict the timing of resolution or the results of the appeals. In the event the order is ultimately changed, the changes are expected to be prospective.

 

Procurement Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. Under the terms of the auction, one-third of the contracted load expired in May 2008, another one-third expired in May 2009 and the remaining load will expire in May 2010. For the period from June 2008 to May 2009, the ICC approved an interim plan under which ComEd procured a portion of its energy load through an RFP for standard wholesale products. ComEd

 

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purchased the remainder of its energy load for this period on the spot market and through the existing SFCs. 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.

 

Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply. On January 7, 2009, the ICC approved the IPA’s plan for the procurement of ComEd’s expected energy requirements from June 2009 through May 2010 and a portion of ComEd’s expected energy requirements from June 2010 through May 2011. On December 28, 2009, the ICC approved the IPA’s procurement plan covering the period June 2010 through May 2015. See Notes 2 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

 

Other. Illinois law provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the 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. During the years 2009, 2008 and 2007, ComEd does not believe that it had any interruptions that have triggered this damage liability or reimbursement requirement.

 

Construction Budget

 

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities, to ensure the adequate capacity and reliability of its system. Based on PJM’s RTEP, ComEd has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2010 is $935 million.

 

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 rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is a public utility under the Federal Power Act subject to regulation by FERC as to transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation as to pipeline safety and other aspects of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to mandatory reliability standards by the NERC, for which Exelon has a company-wide NERC Reliability Standards Compliance Program.

 

PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.7 million. PECO provides electric delivery service in an area of approximately 1,900 square miles, with a population of approximately 3.7 million,

 

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including 1.4 million in the City of Philadelphia. PECO supplies natural gas service in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.6 million customers and natural gas to approximately 485,000 customers.

 

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

 

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

 

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

 

Retail Electric Services

 

Pennsylvania permits competition by competitive electric generation suppliers for the supply of retail electricity while transmission and distribution service remains regulated. At December 31, 2009, less than 1% of PECO’s residential and large commercial and industrial loads and 6% of its small commercial and industrial load were purchasing generation service from competitive electric generation suppliers.

 

Under the 1998 restructuring settlement, in accordance with the Competition Act, PECO’s electric generation rates are capped through a transition period ending December 31, 2010.

 

During the transition period, PECO has been authorized to recover $5.3 billion of costs that might not otherwise be recovered in a competitive market (stranded costs) with a 10.75% return on the unamortized balance through the imposition and collection of non-bypassable CTCs on customer bills. The 1998 restructuring settlement also authorized PECO to securitize up to $5 billion of its stranded cost recovery. At December 31, 2009, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was approximately $883 million, which will be fully amortized in 2010. For 2010, PECO estimates collections of CTC revenue of $1,032 million. In 2010, to the extent the actual recoveries of CTCs differ from the authorized amount, a quarterly or monthly reconciliation adjustment to the CTC rates will be made to increase or decrease future remaining collections accordingly. The billing of CTCs will cease on December 31, 2010.

 

PECO has a PPA with Generation under which PECO obtains all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues PECO is authorized to recover from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act.

 

Pennsylvania Transition-Related Legislative and Regulatory Matters. In Pennsylvania, despite the recent decline in wholesale electricity market prices, there has been some continuing interest from elected officials in mitigating the potential impact of electric generation price increases on customers

 

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when rate caps expire. While PECO’s retail electric generation rate cap transition period does not end until December 31, 2010, transition periods have ended for seven other Pennsylvania electric distribution companies, and, in most instances, post-transition electric generation price increases occurred. In recent years, elected officials in Pennsylvania have suggested legislation to address concerns over post-transition electric generation price increases. Measures suggested by legislators include rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs.

 

During 2009, PECO received PAPUC approval of its Market Rate Transition Phase-In Program and the settlement of its DSP Program. The DSP Program, which has a 29-month term beginning January 1, 2011 and ending May 31, 2013, complies with electric supply procurement guidelines set forth in Act 129 and will provide default electric service following the expiration of electric generation rate caps on December 31, 2010. In accordance with the DSP Program, PECO conducted two competitive procurements for electric supply for default electric service customers commencing January 2011. PECO has procured approximately 50% of the total estimated electric supply needed to serve the residential customer class in 2011. The results of these procurements indicate a price increase of 4%, on average, over current prices for residential customers. The actual price change will not be known until all the scheduled procurements have been completed.

 

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

 

Smart Meter and Energy Efficiency Programs

 

Smart Meter Programs. PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On November 25, 2009, PECO filed a joint petition for partial settlement of its $550 million Smart Meter Procurement and Installation Plan with the PAPUC, which was filed on August 14, 2009 in accordance with the requirements of Act 129. On January 28, 2010, the ALJ issued an initial decision approving the partial settlement and determining remaining cost allocation issues subject to final PAPUC approval. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in June 2010, and for approval of a universal meter deployment plan for its remaining customers in 2012.

 

On October 27, 2009, the DOE announced its intent to award PECO $200 million in the ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full award on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 smart meters within three years and then accelerating universal smart meter deployment from 15 years to 10 years.

 

Energy Efficiency Programs. Pursuant to Act 129’s energy efficiency and conservation/demand (EE&C) reduction targets, PECO filed its EE&C plan with the PAPUC on July 1, 2009. On October 28, 2009, the PAPUC issued an order providing partial approval of PECO’s EE&C plan. The approved plan totals more than $330 million and includes the CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. On December 24, 2009, PECO filed revisions to the portions of the plan not approved based on PAPUC feedback.

 

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

 

Natural Gas

 

PECO’s natural gas sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a portion of total rates, are subject

 

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to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates. In October 2008, the PAPUC approved a settlement of a gas distribution rate increase that provides for an annual revenue increase of $77 million. The approved distribution rate adjustment became effective on January 1, 2009.

 

PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. Approximately 35% of PECO’s current total yearly throughput is provided by natural gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial and industrial customers. Natural gas transportation service provided to customers by PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services at regulated rates.

 

PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to two years. These purchases are primarily delivered under long-term firm transportation contracts. 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 2009-2010 heating season planned supplies.

 

Construction Budget

 

PECO’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, PECO has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2010 is $500 million. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further information.

 

ComEd and PECO

 

Transmission Services

 

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

 

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

 

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

 

ComEd’s most recent annual formula rate update filed in May 2009 reflects actual 2008 expenses and investments plus forecasted 2009 capital additions. The update resulted in a revenue requirement of $436 million resulting in an increase of approximately $6 million from the 2008 revenue requirement, plus an additional $4 million related to the 2008 true-up of actual costs. The 2009 revenue requirement of $440 million, which includes the 2008 true-up, became effective June 1, 2009 and is recovered over the period extending through May 31, 2010. The regulatory asset associated with the true-up is being amortized as the associated revenues are received. ComEd will continue to reflect its best estimate of its anticipated true-up in the financial statements.

 

The Competition Act, Pennsylvania’s electric utility restructuring legislation, was adopted in 1996 and unbundled electric generation, transmission and distribution services. PECO’s most recently approved bundled rate for these services was approved in 1990 and established a weighted average debt and equity return on its electric rate base of 11.23%. As a result of PECO’s 1998 restructuring settlement, retail transmission rates were capped at the level in effect on December 31, 1996. The cap expired on December 31, 2006, however those rates will continue to be in effect until PECO files a rate case or there is some other specific regulatory action to adjust retail transmission rates. PECO’s transmission rate included in the PJM Open Access Transmission Tariff is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for transmission service. The PAPUC approves how PECO recovers this cost through its retail transmission rates.

 

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

 

Employees

 

As of December 31, 2009, Exelon and its subsidiaries had 19,329 employees in the following companies, of which 8,728 or 45% are covered by collective bargaining agreements (CBAs):

 

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

Generation

   1,690    242    1,787    3,719    9,616

ComEd

   3,639    —      —      3,639    5,819

PECO

   —      1,254    —      1,254    2,391

Other (d)

   89    —      27    116    1,503
                        

Total

   5,418    1,496    1,814    8,728    19,329
                        

 

(a) A separate CBA between ComEd and IBEW Local 15, ratified on November 20, 2009, covers approximately 130 employees in ComEd’s System Services Group.
(b) 1,254 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 242 employees.
(c) During 2009 and early 2010, CBAs were agreed to with the following Security Officers unions: Braidwood, Byron, Clinton, Dresden, Oyster Creek and TMI. The agreements generally expire during 2012 except for the agreements at Clinton and Oyster Creek, which expire in 2013. Additionally, during 2009, a 5-year agreement was reached with Oyster Creek Nuclear Local 1289, which will expire in 2015.
(d) Other includes shared services employees at BSC.

 

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Environmental Regulation

 

General

 

Exelon, Generation, ComEd and PECO are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where the Registrants operate their facilities. The U.S. EPA administers certain Federal statutes relating to such matters, as do various interstate and local agencies. Various state and local environmental protection agencies or boards have jurisdiction over certain activities in states in which Exelon and its subsidiaries do business. State and local regulation includes the authority to regulate air, water and noise emissions and solid waste disposals.

 

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

 

Water

 

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

 

In July 2004, the U.S. EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule established national performance standards for reducing the impact on aquatic organisms at existing power plants and provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to this regulation. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Following legal challenges to the Phase II Rule, the Rule has been withdrawn and remanded to the U.S. EPA for revisions consistent with the courts’ decisions. In the interim, Generation has been complying with the requirements of the state permitting agencies, which are administering the Rule pursuant to their best professional judgment until a new final Rule is issued by the U.S. EPA. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require the installation of cooling towers within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until the draft permit is

 

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finalized after a period of public comment. Generation believes the public comment period and regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

 

Generation estimates that the cost to retrofit Oyster Creek with closed-cycle cooling towers would be approximately $700 million to $800 million. This cost estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing operations and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029, and Generation would close Oyster Creek if either the final Section 316(b) regulations or NJDEP requirements have performance standards that require the installation of cooling towers. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. For example, should PJM require the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

 

In 2005 and 2006, the Illinois EPA issued NOVs to Generation alleging violations of state groundwater standards at the Braidwood, Dresden and Byron generating stations. Exelon and Generation are in litigation with the Illinois EPA regarding these NOVs and cannot determine the outcome of these matters but believe their ultimate resolution should not, after consideration of reserves established, have a material impact on Exelon’s or Generation’s respective results of operations, cash flows or financial position. See Note 18 of the Combined Notes to Consolidated Financial Statements for discussion of NOVs received by Generation related to violations of Illinois state groundwater standards.

 

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

 

Solid and Hazardous Waste

 

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

 

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

 

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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 and PECO perform a detailed study of the MGP reserve on an annual basis and believe that appropriate reserves have been recorded. Since ComEd, pursuant to an ICC order, and PECO, pursuant to the joint settlement of the 2008 gas distribution rate case, are recovering environmental costs of remediation of the MGP sites through a provision within customer rates, future estimated recoveries are recorded as a regulatory asset. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Costs of Environmental Remediation

 

At December 31, 2009, Exelon had accrued $175 million, consisting of $17 million, $113 million, and $45 million at Generation, ComEd and PECO, respectively, for various environmental investigation and remediation alternatives. Exelon has recorded a regulatory asset of $143 million, consisting of $103 million and $40 million at ComEd and PECO, respectively, related to the recovery of MGP remediation costs. See Notes 18 and 19 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The amount to be expended in 2010 at Exelon for compliance with environmental remediation is expected to total $23 million, consisting of $1 million, $19 million and $3 million at Generation, ComEd and PECO, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

 

Cotter Corporation

 

The U.S. EPA has advised Cotter Corporation, a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs. Generation, which assumed ComEd’s potential liability, has accrued what it believes to be an adequate amount within the estimated cost range to cover its anticipated share of the liability. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

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 emission sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically.

 

The Amendments establish a comprehensive and complex national program to substantially reduce air pollution, including a two-phase program to reduce acid rain effects by significantly reducing emissions of SO2 and NOx from power plants. Flue-gas desulfurization systems (SO2 scrubbers) have been installed at all of Generation’s coal-fired units.

 

In addition to Federal and state regulatory activities, several legislative proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, have been proposed in the United States Congress. For example, several multi-pollutant bills have been

 

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introduced in past years that would reduce generating plant emissions of NOx, SO2, mercury and carbon. At this time, Generation can provide no assurance that new legislative and regulatory proposals, if adopted, will not have a significant effect on Generation’s operations, cash flows, or financial position.

 

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding national clean air legislation in the forms of the CAIR and CAMR, in addition to Keystone’s compliance with the Acid Rain Program Phase II limits and NOVs issued to Generation and ComEd for 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. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear and hydroelectric), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide (CO2) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions from the direct combustion of fossil fuels, primarily at its 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; this is also a highly variable component of its GHG emissions to forecast due to the primarily intermediate and peaking profile of Exelon’s fossil generating fleet. However, only approximately 6% of Exelon’s total electric supply is provided by its fossil fuel generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the gas pipeline system and the coal piles at its generating plants, 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 climate change.

 

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding international, Federal, regional and state climate change legislation and regulation and its potential impact on Exelon.

 

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

 

Despite Exelon’s low GHG emission inventory and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. Exelon made this pledge under the U.S. EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. The U.S. EPA confirmed on April 6, 2009 that Exelon achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the retirement of older, inefficient fossil power plants, reduced leakage of SF6, increased use of renewable energy and its current energy efficiency initiatives. Based on its verified GHG emissions inventory, Exelon’s 2008 carbon dioxide-equivalent (CO2-e) emissions were 9.7 million metric tons.

 

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Compared to its 2001 baseline of 15.7 million metric tons of CO2-e emissions, Exelon achieved a reduction of nearly 6.0 million metric tons (a 38% reduction below baseline) at the end of 2008. The cost of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s results of operations, cash flows or financial position.

 

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. 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 new portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs at PECO to meet the requirements of the recently enacted 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 applications. 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. Exelon has recently completed a periodic review of the original analysis of the costs and abatement potential of various emissions-reducing opportunities and remains committed to achieving the goal put forward in 2008. 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.

 

FutureGen Alliance

 

Exelon supports efforts to develop new technologies to help reduce GHG emissions but recognizes that many opportunities to invest in new and emerging technologies are not yet commercially viable without Federal and state financial support. On January 30, 2010, Exelon announced that Generation intends to become a member of the FutureGen Alliance (FutureGen), which has been established to help fund a clean coal technology demonstration plan in Mattoon, Illinois. The proposed arrangement between Generation and FutureGen is subject to a number of conditions, including the execution of definitive agreements for participation by Generation and other contributing members. The proposed arrangement contemplates that Generation would make phased contributions of up to $32.1 million over a period of up to six years, commencing with the execution of a Cooperative Agreement between FutureGen and the DOE to provide partial funding for the project. Contributing members would have rights to withdraw from participation before a decision is made to start actual construction of the project or if there are insufficient funds to complete the project. Construction of the project is dependent on funding from contributing members, a grant of more than $1 billion from DOE, and financing from other sources.

 

Renewable and Alternative Energy Portfolio Standards

 

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

 

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The Illinois Settlement Legislation required that procurement plans implemented by electric utilities include cost-effective renewable energy resources 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 subject to legislated rate impact criteria. ComEd procured approximately $19 million in RECs under the ICC-approved RFP for the period June 2008 through May 2009. On May 13, 2009, the ICC approved the results of an RFP to procure RECs for a total cost of $31 million for the period June 2009 through May 2010. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The AEPS Act mandates that 1.5% to 8.0% and 4.2% to 10.0% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers shall be generated from Tier I and Tier II alternative energy resources, respectively, as measured in AECs. During 2009, PECO entered into agreements with accepted bidders, including Generation, for the purchase of 412,000 AECs annually for five years beginning no later than December 31, 2009. This agreement along with the five-year agreement entered into during 2008 for the purchase of 40,000 AECs annually were executed in accordance with its PAPUC approved plan to acquire and bank approximately 450,000 non-solar Tier I AECs annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance with the AEPS Act following the completion of its electric generation rate cap transition period.

 

In August 2009, the PAPUC approved a joint petition filed by PECO and various interveners for expedited approval of PECO’s early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. On January 25, 2010, the PAPUC approved the fixed-price agreement solar AEC procurement results. PECO plans to enter into the fixed-price agreements by February 8, 2010.

 

While Generation is not directly affected by RPS or AEPS legislation from a compliance perspective, increased deployment of renewable and alternative energy resources will affect regional energy markets and, at the same time, may present some opportunities for sales of Generation’s renewable power, including from Generation’s hydroelectric and landfill gas generating stations and wind energy PPAs.

 

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

 

Executive Officers of the Registrants as of February 5, 2010

 

Exelon

 

Name

   Age   

Position

Rowe, John W.

   64    Chairman and Chief Executive Officer, Exelon; Chairman, Generation

Crane, Christopher M.

   51    President and Chief Operating Officer, Exelon and Generation

Clark, Frank M.

   64    Chairman and Chief Executive Officer, ComEd

O’Brien, Denis P.

   49    Executive Vice President, Exelon; Chief Executive Officer and President, PECO

Gillis, Ruth Ann

   55    Executive Vice President and Chief Administrative and Diversity Officer, Exelon; President, Exelon Business Services Company

McLean, Ian P.

   60    Executive Vice President, Exelon and Chief Executive Officer, Exelon Transmission Company

Moler, Elizabeth A.

   61    Executive Vice President, Government Affairs and Public Policy

Von Hoene Jr., William A.

   56    Executive Vice President, Finance and Legal

Zopp, Andrea L.

   53    Executive Vice President and General Counsel

Cornew, Kenneth W.

   44    Senior Vice President, Exelon; President, Power Team division of Generation

Hilzinger, Matthew F.

   46    Senior Vice President and Chief Financial Officer

DesParte, Duane M.

   46    Vice President and Corporate Controller

 

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Generation

 

Name

   Age   

Position

Rowe, John W.

   64    Chairman and Chief Executive Officer, Exelon; Chairman

Crane, Christopher M.

   51    President and Chief Operating Officer, Exelon and Generation

Pardee, Charles G.

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

Cornew, Kenneth W.

   44    Senior Vice President, Exelon; President, Power Team

Beneby, Doyle N.

   50    Senior Vice President, Exelon Generation, Acting President Exelon Power

Hilzinger, Matthew F.

   46    Senior Vice President and Chief Financial Officer, Exelon (Principal Financial Officer)

Galvanoni, Matthew R.

   37    Vice President and Assistant Corporate Controller, Exelon; Chief Accounting Officer (Principal Accounting Officer)

 

ComEd

 

Name

   Age   

Position

Clark, Frank M.

   64    Chairman and Chief Executive Officer

Pramaggiore, Anne R.

   51    President and Chief Operating Officer

Hooker, John T.

   61    Executive Vice President, Legislative and External Affairs

Donnelly, Terence R.

   49    Executive Vice President, Operations

Bradford, Darryl M.

   54    Senior Vice President, Regulatory and Energy Policy and General Counsel

Butler Jr., Calvin G.

   40    Senior Vice President, ComEd Corporate Affairs

Marquez, Fidel

   48    Senior Vice President, Customer Operations

Trpik Jr., Joseph R.

   40    Senior Vice President, Chief Financial Officer and Treasurer

Waden, Kevin J.

   38    Vice President and Controller

 

PECO

 

Name

   Age   

Position

O’Brien, Denis P.

   49    Executive Vice President, Exelon; Chief Executive Officer and President

Adams, Craig L.

   57    Senior Vice President and Chief Operating Officer

Barnett, Phillip S.

   46    Senior Vice President and Chief Financial Officer

Bonney, Paul R.

   51    Vice President, Regulatory Affairs and General Counsel

Diaz Jr., Romulo L.

   63    Vice President, Governmental and External Affairs

Acevedo, Jorge A.

   38    Vice President and Controller

 

Each of the above executive officers holds such office at the discretion of the respective Registrant’s board of directors or governing body, as applicable, until his or her replacement or earlier resignation, retirement or death.

 

Prior to his election to his listed positions, Mr. Rowe was Chairman, Chief Executive Officer and President of Exelon from 2004 to 2008 and has served as Chairman and Chief Executive Officer of Exelon since 2002.

 

Prior to his election to his listed position, Mr. Crane was Executive Vice President, Exelon and Chief Operating Officer, Generation from 2007 to 2008; Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear from 2004 to 2007.

 

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Prior to his election to his listed positions, Mr. Clark was Executive Vice President and Chief of Staff of Exelon and President of ComEd from 2004 to 2005. Mr. Clark is listed as an executive officer of Exelon by reason of his position as the Chairman and Chief Executive Officer of ComEd.

 

Prior to his election to his listed position, Mr. O’Brien was President of PECO from 2003 to 2007.

 

Prior to her election to her listed position, Ms. Gillis was Executive Vice President, Exelon and President, Exelon Business Services Company from 2008 through 2009. Previously, she was Senior Vice President, Exelon and President, Exelon Business Services Company from 2005 to 2008; and Senior Vice President, Exelon, and Executive Vice President, ComEd from 2004 to 2005.

 

Prior to his election to his listed position, Mr. McLean was Executive Vice President, Finance and Markets from 2008 to 2009; and Executive Vice President, Exelon and President of the Exelon Power Team division of Generation from 2002 to 2008.

 

Prior to her election to her listed position, Ms. Moler was Executive Vice President, Governmental and Environmental Affairs and Public Policy from 2002 through 2009.

 

Prior to his election to his listed position, Mr. Von Hoene was Executive Vice President and General Counsel from 2008 to 2009; Senior Vice President and General Counsel, Exelon from 2006 to 2008; Senior Vice President and Acting General Counsel, Exelon from 2005 to 2006; and Senior Vice President and Deputy General Counsel, Exelon from 2004 to 2005.

 

Prior to her election to her listed position, Ms. Zopp was Executive Vice President, Exelon and Chief Human Resources Officer from 2008 through 2009; Senior Vice President, Exelon and Chief Human Resources Officer from 2007 to 2008; Senior Vice President, Human Resources, Exelon from 2006 to 2007; and Senior Vice President, General Counsel and Corporate Secretary, Sears Holding Corporation from 2003 to 2005.

 

Prior to his election to his listed position, Mr. Cornew held the following positions in the Power Team division of Generation: Senior Vice President, Trading and Origination from 2007 to 2008 and Senior Vice President, Power Transactions and Wholesale Marketing from 2004 to 2007.

 

Prior to his election to his listed position, Mr. Hilzinger was Senior Vice President, Exelon and Corporate Controller from 2005 to 2008; and Vice President, Exelon and Corporate Controller from 2002 to 2005. Mr. Hilzinger was Principal Accounting Officer for ComEd and PECO through December 31, 2006.

 

Prior to his election to his listed position, Mr. DesParte was Vice President, Finance of BSC from 2007 to 2008 and Vice President, Exelon Energy Delivery from 2004 to 2006.

 

Prior to his election to his listed position, Mr. Pardee was Senior Vice President, Generation and Chief Nuclear Officer, Exelon Nuclear from 2007 to 2008; Senior Vice President and Chief Operating Officer, Exelon Nuclear from 2005 to 2007; and Senior Vice President Engineering and Technical Services from 2004 to 2005.

 

Prior to his election to his listed position, Mr. Beneby was Vice President, Power Operations from 2008 to 2009; Vice President, Construction and Maintenance, PECO from 2006 to 2008; Vice President, Electric Operations, PECO from 2005 to 2006; and Vice President, Engineering and System Performance, Exelon Energy Delivery from 2004 to 2005.

 

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Prior to his election to his listed position, Mr. Galvanoni was Vice President and Controller, ComEd and PECO from 2006 through 2009; Director of Financial Reporting and Analysis, Exelon during 2006; and Director of Accounting and Reporting, Generation from 2004 to 2005.

 

Prior to her election to her listed position, Ms. Pramaggiore was Executive Vice President, Customer Operations, Regulatory and External Affairs from 2007 to 2009; Senior Vice President, Regulatory and External Affairs, ComEd from 2005 to 2007; and Vice President, Regulatory and Strategic Services from 2002 to 2005.

 

Prior to his election to his listed position, Mr. Hooker was Senior Vice President, State Governmental Affairs and Real Estate and Facilities from 2008 to 2009; Senior Vice President, ComEd, Legislative and External Affairs from 2005 to 2008; and Senior Vice President, Exelon Energy Delivery Real Estate and Property Management from 2003 to 2005.

 

Prior to his election to his listed position, Mr. Donnelly was Senior Vice President, Transmission and Distribution, ComEd from 2007 through 2009; Senior Vice President, Technical Services, ComEd and PECO in 2007; and Vice President, Transmission and Substations, ComEd and PECO from 2004 through 2007.

 

Prior to his election to his listed position, Mr. Bradford was the Senior Vice President and General Counsel of ComEd from 2007 through June 2009; Vice President, General Counsel, ComEd from 2005 to 2007; and Vice President, Associate General Counsel, ComEd from 2003 to 2007.

 

Prior to his election to his listed position, Mr. Butler was Senior Vice President, Large Customer Services, State Legislative and Government Affairs, ComEd from May 2009 to January 2010; Vice President, State Legislative and Government Affairs, ComEd from 2008 to 2009; Senior Vice President, External Affairs, RR Donnelley from 2005 to 2008; and Vice President of Operations, Pontiac Division, RR Donnelley from 2004 to 2005.

 

Prior to his election to his listed position, Mr. Marquez was Vice President of External Affairs and Large Customer Services from 2007 to May 2009, and Vice President of External Affairs, ComEd, from 2004 to 2007.

 

Prior to his election to his listed position, Mr. Trpik was Vice President and Assistant Corporate Controller, Exelon, from 2004 through 2009.

 

Prior to his election to his listed position, Mr. Waden was Director of Accounting Operations, ComEd from 2007 through 2009; and Director of Financial Reporting and Accounting Research, Exelon Energy Delivery, LLC from 2003 through 2006.

 

Prior to his election to his listed position, Mr. Adams was Senior Vice President and Chief Supply Officer, BSC from 2004 to 2007.

 

Prior to his election to his listed position, Mr. Barnett was Senior Vice President, Corporate Financial Planning, Exelon, from 2005 to 2007; and Vice President Finance, Exelon Generation from 2003 to 2005.

 

Prior to his election to his listed position, Mr. Bonney was Vice President and Deputy General Counsel, Regulatory from 2001 to 2006.

 

Prior to his election to this listed position, Mr. Diaz was Associate General Counsel, Exelon from 2008 through 2009; City Solicitor, City of Philadelphia from 2005 through 2008; and Chair of the Commercial and Regulatory Law Group, City of Philadelphia from 2002 through 2005.

 

Prior to his election to his listed position, Mr. Acevedo was Assistant Controller of Generation from 2007 through July 2009; and Director of Accounting, Power Team, from 2003 through 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 each Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the RMC, which is comprised of officers of the Registrants, to identify and evaluate the most significant risks of the Registrant’s businesses, and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Risk Oversight and Audit Committees of the Exelon Board of Directors and the ComEd and PECO Boards of Directors. In addition, the Exelon Board of Directors’ Generation Oversight and Energy Delivery Oversight Committees, respectively, evaluate risks related to the generation and energy delivery businesses. The risk factors discussed below may adversely affect one or more of the Registrants’ results of operations and cash flows and the market prices of their publicly-traded securities. Each of the Registrants has disclosed the material risks known to it to affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may in the future adversely affect its performance or financial condition.

 

The Registrants’ most significant risks arise as a consequence of: (1) Generation’s position as a predominantly nuclear generator selling power into competitive wholesale markets, and (2) the role of both ComEd and PECO as operators of electric transmission and distribution systems in two of the largest metropolitan areas in the United States. The Registrants’ major risks fall primarily under the categories of market and financial risk, regulatory and legislative risk, and operational risk.

 

First, Exelon and Generation have exposure to certain market and financial risks, including 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, and in particular the price of natural gas and coal, that drive the wholesale market prices that Generation’s nuclear power plants can command, the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, and the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs.

 

Second, the Registrants face regulatory and legislative risks, including 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 the power it produces and sell into the competitive wholesale power markets at market-based prices. In addition, potential 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 could hope to derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future.

 

Third, the Registrants face a number of operational risks, including those risks inherent in running the nation’s largest fleet of nuclear power reactors and large electric distribution systems. The safe and effective operation of the nuclear facilities and the ability to effectively manage its 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.

 

Finally, 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 availability, reliability and safety of their energy delivery systems. A discussion of each of these risks and other risk factors is included below.

 

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Market and Financial Risks

 

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

 

Generation fulfills its energy supply commitments from the output of the generating facilities that it owns as well as through buying electricity under long-term and short-term contracts in both the wholesale bilateral and spot markets. The excess or deficiency of energy owned or controlled by Generation compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. Generation’s cash flows from generation that is not used to meet Generation’s long-term supply commitments are largely dependent on wholesale prices of electricity and Generation’s ability to successfully market energy, capacity and ancillary services.

 

The wholesale spot market price of electricity for each hour is generally determined by the 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. Consequently, the open-market wholesale price of electricity likely reflects the cost of fossil fuels plus the cost to convert to electricity. Therefore, changes in the supply and cost of fossil fuels generally affect the open market wholesale price of electricity. In the event that alternative generation resources, such as wind and solar, are mandated through RPS or otherwise subsidized or encouraged through climate legislation and added to the supply, they could displace a higher cost fossil plant, which could reduce the price at which market participants sell their electricity. This could then reduce the market price at which all generators in that region, including Generation, would sell their output.

 

The market price for electricity is also affected by changes in the demand for electricity. Economic conditions, weather, and increases in energy efficiency and demand response can impact demand and prevent higher-cost generating resources from being called upon, effectively lowering the market price received for electricity.

 

The continued sluggish economy in the United States has led to reduced demand for electricity and lower prices for electricity and other commodities, which will adversely affect the Registrants’ financial condition, results of operations and cash flows. This could adversely affect the Registrants’ ability to pay dividends or fund other discretionary uses of cash such as growth projects. The weak world economy reduced the international demand for coal, oil and natural gas, and led to sharply lower fossil fuel prices putting downward pressure on electricity prices. The use of new technologies to recover natural gas from shale deposits is expected to increase natural gas supply and reserves, which will tend to place further downward pressure on natural gas prices and could reduce Generation’s revenues. A slow recovery of the economy could result in a prolonged depression of or further decline in commodity prices, which could adversely affect Exelon’s and Generation’s results of operations, cash flows and financial position.

 

In addition to price fluctuations, Generation is exposed to other risks of the wholesale power market that are beyond its control, which may negatively impact 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 the risks of whatever default mechanisms exist in that market, some of which attempt to spread the risk across all

 

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participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, the retail businesses subject Generation to credit risk through competitive electricity and natural gas supply activities that 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 are 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 economic factors may decrease the value of decommissioning trust funds and benefit plan assets or 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 Exelon’s employee benefit plan trusts and Generation’s NDTs. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts. The asset values are subject to market fluctuations and will yield uncertain returns, which may fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments may increase the funding requirements to decommission Generation’s nuclear plants. A decline in the market value of the pension and other postretirement benefit plan assets will increase the funding requirements associated with Exelon’s pension and other postretirement benefit plans. Additionally, Exelon’s pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. Also, 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 successfully manage the decommissioning trust funds and benefit plan assets and obligations, their results of operations and financial positions could be negatively affected.

 

Disruptions in the 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. Further disruptions in the capital and credit markets, or further deterioration of the banks’ financial condition could adversely affect the Registrants’ ability to 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

 

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Market and Financial Risks Continued

 

are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy to reduce collateral-posting requirements, or a reduction in dividend payments or other discretionary uses of cash.

 

The strength and depth of competition in competitive energy markets depends 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 those 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 the Registrants were to experience a downgrade in their credit ratings below investment grade or otherwise fail to satisfy the credit standards of trading counterparties, they would be required to provide significant amounts of collateral under their agreements with counterparties and could experience higher borrowing costs. (Exelon, Generation, ComEd and PECO)

 

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

 

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

 

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Market and Financial Risks Continued

 

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 supportive regulatory environment in Illinois or Pennsylvania becomes less predictable by materially lowering returns for utilities in the state or adopting other measures to manage higher electricity prices. Additionally, the ratings for ComEd or PECO could be downgraded if either company’s financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of ComEd or PECO.

 

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 and 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.

 

Results of operations may be negatively affected by increasing costs. (Exelon, Generation, ComEd and PECO)

 

Inflation affects the Registrants through increased operating costs and increased capital costs for plant and equipment. In addition, the Registrants face rising medical benefit costs, including the current costs for active and retired employees. These medical benefit costs are increasing at a rate that is significantly greater than the rate of general inflation. Additionally, it is possible that these costs may increase at a rate that is higher than anticipated by the Registrants. If the Registrants are unable to successfully manage their medical benefit costs, pension costs, or other increasing costs, their results of operations could be negatively affected.

 

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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. It is not possible to accurately predict the future cost or availability of these commodities.

 

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.

 

Power Team 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 these tests administered by FERC, it could be limited in how it responds to increased demand for energy.

 

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

 

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

 

1999 sale of fossil generating assets. The IRS has challenged Exelon’s 1999 tax position on an involuntary conversion and like-kind exchange transaction. If the IRS is successful in its challenge, 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, 2009, Exelon’s and ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $1.1 billion excluding penalties. If the deferral were successfully challenged by the IRS, it could also negatively affect Exelon’s and ComEd’s results of operations by up to $300 million (after tax) related to interest expense. In addition to attempting to impose tax on the above transactions, the IRS has asserted penalties for a substantial understatement of tax, which could result in an after-tax charge of $196 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 this matter are unknown. See Note 10 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 for which the benefits have already been reflected, and tax credits. See Notes 1 and 10 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, increasing rates could lead to decreased volumes delivered. Both of these factors may decrease ComEd’s and PECO’s results from operations and cash flows. (Exelon, ComEd and PECO)

 

ComEd’s current procurement plan includes purchasing power through contracted suppliers and the spot market. Purchased power prices fluctuate based on the supply and demand for electricity, which could lead to higher customer bills and potentially additional uncollectible accounts expense.

 

The cost of PECO’s purchased power, which is provided by Generation through a PPA, is capped as part of the transition period through 2010. For service following the end of PECO’s transition period, PECO will purchase power on the open market, with no return or profit to PECO, which may significantly increase the cost of power PECO procures and in turn increase costs to the customer. The increase in rates could cause customer usage to decrease, resulting in lower transmission and distribution revenues and lower profit margins for PECO.

 

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Gas rates charged to PECO customers are comprised primarily of purchased natural gas cost charges, which provide no return or profit to PECO, and distribution charges, which provide a return or profit to PECO. Purchased natural gas cost charges, which comprise most of a customer’s bill and may be adjusted quarterly, are designed for PECO to recover the cost of the natural gas commodity and pipeline transportation and storage services that PECO procures to service its customers. Gas rates may change quarterly based on market conditions, which may lead to higher prices and potentially additional uncollectible accounts expense. PECO’s cash flows can be affected by differences between the time period when natural gas is purchased and the ultimate recovery from customers. If purchased natural gas cost charges increase substantially reflecting higher natural gas procurement costs incurred by PECO, customer usage may decrease, resulting in lower distribution charges and lower profit margins for PECO.

 

In addition to increased purchased power for ComEd and PECO customers and purchased natural gas costs for PECO customers, economic downturns and the related limitations on service termination 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.

 

In accordance with PAPUC regulations, after November 30 of any year and before April 1 of the following year, an electric distribution utility or natural gas distribution utility cannot terminate service to customers with household incomes at or below 250% of the Federal poverty level. As a result, PECO may be delayed in stopping service to customers who are delinquent in their bills, which increases PECO’s uncollectible accounts expense.

 

The Illinois Settlement Legislation prohibits utilities from terminating electric service to an Illinois residential space-heating customer due to nonpayment, extending from December 1 of any year through March 1 of the following year. ComEd’s ability to disconnect non space-heating residential customers is also affected by certain weather restrictions, at any time of year, under the Illinois Public Utilities Act. As a result, ComEd may be delayed in stopping service to customers who are delinquent in their bills, which could increase ComEd’s uncollectible accounts expense.

 

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 can impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, may have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak.

 

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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)

 

The Registrants evaluate the carrying value of long-lived assets to be held and used for impairment whenever indications of impairment exist. The carrying value of a long-lived asset is considered impaired when the carry value is not recoverable and exceeds its fair value. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. In the event that a long-lived asset is impaired, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available market valuations or, if applicable, future discounted estimated cash flows or other valuation methods. Factors such as the business climate, including current energy and market conditions, and the condition of assets are considered when evaluating long-lived assets for impairment. An impairment would require Generation to reduce the long-lived asset through a charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact on Exelon’s and Generation’s results of operations.

 

Exelon and ComEd both had approximately $2.6 billion of goodwill recorded at December 31, 2009 in connection with the merger between PECO and Unicom Corporation, the former parent company of ComEd. Under GAAP, goodwill will remain at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off and expensed, reducing equity.

 

The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, results of ComEd’s rate proceedings, operating and capital expenditure requirements and other factors, some not yet known. Such a potential impairment would be a noncash charge, which could have a material impact on Exelon’s and ComEd’s operating results.

 

See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Estimates and Note 6 of the Combined Notes to the Consolidated Financial Statements for additional discussion on goodwill impairments.

 

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

 

The Registrants’ businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects. The Registrants’ results of operations could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. See Item 1 of this Form 10-K for further information regarding the Registrants’ potential future capital expenditures.

 

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

 

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

 

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Due to its dependence on its two most significant customers, ComEd and PECO, Generation will be negatively affected in the event of non-performance or change in the creditworthiness of either of its most significant customers. (Exelon and Generation)

 

Generation currently provides power under procurement contracts with ComEd for a significant portion of ComEd’s electricity supply requirements and a PPA with PECO to meet 100% of PECO’s electricity supply requirements through 2010. 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 and PECO’s continued payments under these procurement contracts and the PPA and would be adversely affected by negative events affecting these agreements, including the non-performance or a significant change in the creditworthiness of either ComEd or PECO. A default by ComEd or PECO under these agreements would have an adverse effect on Generation’s results of operations and financial position.

 

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

 

Because retail customers in both Illinois and Pennsylvania can switch from ComEd or PECO 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 the ComEd load and to supply PECO with all of the energy PECO needs to fulfill its default service obligation is more difficult than planning for retail load before the advent of retail competition. Before retail competition, the primary variables affecting projections of load were weather and the economy. With retail competition, another major factor is the ability of retail customers to switch to competitive electric generation suppliers. If fewer of such customers switch from ComEd or PECO than Generation anticipates, the ComEd and/or PECO 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 of such customers switch than Generation anticipates, the ComEd and/or PECO 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 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. 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 their ability to recover their costs for purchased power and their costs of distribution of power to their customers. In their business planning and in the management of their operations, the Registrants must address the effects of regulation of their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, ratemaking jurisdictions and taxing authorities. Fundamental changes in regulations or other adverse legislative actions impacting the Registrants’ businesses would require changes in their business planning models and operations and could adversely affect their operating results, cash flows and the value of their assets.

 

Legislative and regulatory developments related to climate change and RPS may also significantly affect Exelon’s and Generation’s operating results, cash flows and the value of their assets. Various

 

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proposals for climate legislation and GHG regulation, if enacted into law, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase the market price at which all generators in that region, including Generation, may sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. However, legislation regarding climate change and 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 could hope to 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 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 exceed the marginal cost of operating nuclear plants, claims that this difference is evidence that the competitive model is not working, and resulting calls for some form of re-regulation, the elimination of marginal pricing, the imposition of a generation tax, or some other means of reducing the earnings of Generation and its competitors. As the energy markets continue to mature, a low number of wholesale market power participants entering procurement proceedings may also influence how certain regulators and legislators view the effectiveness of these competitive markets.

 

The criticism of restructured electricity markets, which has escalated in recent years as retail rate freezes expired and prices of electricity increased with rising fuel prices, is expected to continue in 2010. A number of advocacy groups have urged FERC to reconsider its support of competitive wholesale electricity markets and require the RTOs to revise the rules governing the RTO-administered markets. Generation is dependent on wholesale energy markets and open transmission access and rights by which Generation delivers power to its wholesale customers, including ComEd and PECO. Generation uses the wholesale regional energy markets to sell power that Generation does not need to satisfy its long-term contractual obligations, and to purchase power to meet obligations not provided by its own resources. These wholesale markets allow Generation to take advantage of market price opportunities but also expose Generation to market risk.

 

Wholesale markets have only been implemented in certain areas of the country and each market has unique features, which may create trading barriers between the markets. Approximately 80% of Generation’s generating resources, which include directly-owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for policies that favor the development of competitive wholesale power markets, such as the PJM market, and (2) the absence of material changes to market structures that would limit or otherwise negatively affect the competitiveness of the PJM market, such as, for example, withdrawal of significant participants from the regional wholesale markets. Generation could also be adversely affected by efforts of state legislatures and regulatory authorities to respond to the concerns of consumers or others about the costs of energy that are reflected through wholesale markets.

 

In particular, the advocacy groups oppose the RTOs’ use of a “single clearing price” for electricity sold in the RTO markets utilizing locational marginal pricing. FERC conducted conferences which led to a rulemaking on Wholesale Competition in Regions with Organized Electric Markets. On October 17,

 

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2008, FERC issued a Final Rule, Order No. 719, to improve the operation of organized wholesale electric markets in the areas of (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs. A number of entities have filed requests for rehearing with FERC. The outcome of this FERC rulemaking process could significantly affect Generation’s results of operations, financial position and cash flows.

 

In addition, on June 21, 2007, FERC issued a Final Rule on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities. FERC provided clarification to the Final Rule on December 14, 2007. The Final Rule made a number of changes in FERC’s market-based rate analysis and required several market power update filings by Generation, ComEd and PECO, the first of which was made on January 14, 2008. As discussed in more detail in Note 2 of the Combined Notes to Consolidated Financial Statements, during 2009, FERC issued three orders accepting Exelon’s filings, and therefore affirmed that Exelon’s affiliates with market-based rates can continue to make market-based sales. Accordingly, the application of the Final Rule has not had and is not currently expected to have a material adverse effect on Exelon’s and Generation’s results of operations, although the longer term impact will depend on how FERC applies the Final Rule as its enforcement of the rule matures with time and experience.

 

Currently, legislation under consideration in Congress and rulemakings under consideration by the Commodity Futures Trading Commission would require over-the-counter derivative products to be moved to exchanges or be centrally cleared. Power Team currently has substantial unsecured credit with various counterparties available for over-the-counter derivative transactions that could require Generation, or its counterparties, to post additional collateral if they were moved to an exchange or centrally cleared. These rule changes could reduce overall market liquidity and participation, which is a threat to the competitive market model. In addition, these changes could significantly affect Generation’s cash flows.

 

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.

 

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Legislators or regulators may respond to anticipated increases in rates following the end of the retail electric generation rate cap transition period in Pennsylvania on December 31, 2010 by enacting laws or regulations aimed at restricting or controlling those rates or by establishing rate relief programs that could require significant funding from PECO and/or Generation that could adversely affect PECO and/or Generation’s results of operations. (Exelon, Generation and PECO)

 

In Pennsylvania, there has been some continuing interest from legislators and regulators in mitigating the potential impact of electric generation price increases on customers when rate caps expire. Although Act 129 provides guidelines associated with electricity procurement that support competitive, market-based procurement, elected officials have suggested rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs. PECO and Generation cannot predict whether any of these measures will become law or whether elected officials or regulators might take action that could have a material impact on the procurement process. If the price that PECO is allowed to bill to customers for electricity is below PECO’s cost to procure and deliver electricity, PECO expects that it will suffer adverse consequences, which could be material.

 

The Illinois Settlement Legislation enacted in 2007 providing rate relief to Illinois electric customers and requiring other changes in the electric industry in lieu of harmful alternatives such as rate freezes, caps, or a tax on generation, could be reversed or modified by new legislation that could be harmful to ComEd and Generation. (Exelon, Generation and ComEd)

 

The Illinois Settlement Legislation enacted in 2007 reflects the Illinois Settlement reached by ComEd, Generation, and other utilities and generators in Illinois with various parties concluding discussions of measures to address higher electric bills experienced in Illinois since the end of the legislatively mandated transition and rate freeze at the end of 2006. The Illinois Settlement Legislation addressed those concerns without implementing a rate freeze, generation tax, or other alternative measures that Exelon believes would have been harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. For more information regarding potential risks associated with such legislation, see “Illinois Settlement Agreement” and “Retail Electric Services” in ITEM 1 of this Form 10-K. Although the Illinois Settlement Legislation allows the contributors to the rate relief to terminate their funding commitments and recover any undisbursed funds set aside for rate relief in the event that, prior to August 1, 2011, the Illinois General Assembly passes legislation that freezes or reduces electric rates of or imposes a generation tax on parties to the Illinois Settlement, there is no guarantee that such legislation will not be passed and enacted in Illinois. The experience in Illinois in 2007 suggests a risk that the Illinois General Assembly may threaten extreme measures again in the future in an attempt to force electric utilities and generators to make further concessions. Such legislation, if enacted, could have a material adverse effect on ComEd and Generation’s results of operations, financial position, and cash flows.

 

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

 

The businesses in which the Registrants operate are subject to extensive environmental regulation 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 and are an important aspect of their operations. 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 or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages. In addition, the Registrants are subject to liability under these laws for the costs of remediation of environmental contamination of

 

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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 will be 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 the Section 316(b) of the Clean Water Act regulations establishing a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations requires the retrofitting of cooling water intake structures at Oyster Creek, Salem or other Exelon power plants, this could result in material costs of compliance. The amount of the costs required to retrofit Oyster Creek may also negatively impact Generation’s decision to operate the plant after the Section 316(b) of the Clean Water Act matter is ultimately resolved. Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.

 

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

 

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

 

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

 

ComEd and PECO cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania or Federal regulators for establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to

 

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deliver electricity to customers in their respective service territories and will also retain significant POLR and default service obligations to provide electricity service to certain groups of customers in its service area who choose to obtain their electricity from the utility.

 

The ultimate outcome of these regulatory actions will 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 and cash flows. Additionally, lengthy proceedings and time delays in implementing new rates relative to when costs are actually incurred could have a material adverse effect on ComEd’s and PECO’s results of operations and cash flows.

 

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.

 

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, will increase capital expenditures and could significantly impact ComEd and PECO if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, ComEd and PECO. For additional information, see ITEM 1. Business “Environmental Regulation-Renewable and Alternative Energy Portfolio Standards”.

 

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

 

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 cannot estimate the longer-term impact on their respective results of operations and cash flows because of the uncertainties relating to what new facilities will be built, the cost of building those facilities and the allocation ultimately determined by further proceedings. See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The impact of not meeting the criteria of the authoritative 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, 2009, 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, which 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

 

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December 31, 2009, the extraordinary gain could have been as much as $1.7 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2009, the extraordinary charge could have been as much as $1.5 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an extraordinary gain or charge in an equal amount related to ComEd’s and PECO’s regulatory assets and liabilities in addition to a charge against OCI (before taxes) of up to $2.5 billion and $92 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, 6 and 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory issues, ComEd’s goodwill and regulatory assets and liabilities, respectively.

 

Exelon and Generation may incur material costs of compliance if Federal and/or state 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. Select Northeast and Mid-Atlantic states have developed a model rule, via the RGGI, to regulate CO2 emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to reduce GHG emissions is likely to evolve in the future. If these plans become effective, Exelon and Generation may incur material costs either to additionally limit the GHG emissions from their operations or to procure emission allowance credits. The nature and extent of environmental regulation may also impact the ability of Exelon and its subsidiaries to meet the GHG emission reduction targets of Exelon 2020. For example, more stringent permitting requirements may preclude the construction of lower-carbon nuclear and gas-fired power plants. Similarly, a Federal RPS could increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change, see “Global Climate Change” in ITEM 1 of this Form 10-K.

 

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. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with or changes in the reliability standards may subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC and PAPUC impose certain distribution reliability standards on ComEd and PECO, respectively. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.

 

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.

 

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Operational Risks

 

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

 

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

 

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

 

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

 

The United States is currently in a pandemic situation related to the H1N1 virus, but the impact to Exelon is expected to be negligible if there is no change to the current severity of the 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.

 

Additionally, Exelon is affected by changes in weather and the occurrence of hurricanes, storms and other natural disasters in its service territory and throughout the U.S. Severe weather or other natural disasters could be destructive which could result in increased costs including supply chain 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 ComEd and PECO and other committed third-party sales. 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 currently average approximately 24 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 24-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. It is difficult to predict the cost for unknown potential future issues and any required remediation actions.

 

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 30 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 fully decommission its nuclear units.

 

License renewals. Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of any renewed license. 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, and may affect Generation’s ability to fully decommission its nuclear units.

 

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

 

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were

 

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

 

Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident can be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned by Generation or owned by others, may exceed Generation’s resources, including insurance coverage. Additionally, an accident or other significant event at a nuclear plant within the United States, owned by others or Generation, may result in increased regulation and reduced public support for nuclear-fueled energy and significantly affect Generation’s results of operations or financial position.

 

Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance. As of January 1, 2010, 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. NEIL did not make a distribution in 2009, and Generation cannot predict the level of future distributions or if they will continue at all.

 

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 four 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

 

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Operational Risks Continued

 

previous owners of Clinton, TMI Unit No. 1 and Oyster Creek generating stations, if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation were unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units may be negatively affected. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Generation’s cash flows and financial position may be significantly adversely affected. See Note 11 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)

 

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

 

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

 

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

 

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Operational Risks Continued

 

The physical risks associated with climate change could impact the Registrant’s results of operations and cash flows. (Exelon, ComEd and PECO)

 

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

 

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. In addition, as with all utilities, potential concerns over transmission capacity 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. 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)

 

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

 

Due to PECO’s dependence on Generation to fulfill 100% of its electric energy supply requirements under a PPA, PECO could be negatively affected in the event of Generation’s inability to perform under the PPA. (Exelon and PECO)

 

PECO currently acquires 100% of its electric energy and capacity requirements under a PPA with Generation. In accordance with the PPA, the current electric generation rates that PECO pays have been fixed and will continue to be fixed through 2010. In the event that Generation could not perform under the PPA, PECO would be forced to purchase electric energy from alternative sources at potentially higher rates. While PECO believes that this event is unlikely to occur, such an event could have a negative impact on PECO’s results of operations and financial position.

 

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

 

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

Exelon, Generation, ComEd and PECO

 

None.

 

ITEM 2. PROPERTIES

 

Generation

 

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2009:

 

Station

 

Location

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

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

Nuclear (d)

           

Braidwood

  Braidwood, IL   2     Uranium   Base-load   2,360  

Byron

  Byron, IL   2     Uranium   Base-load   2,336  

Clinton

  Clinton, IL   1     Uranium   Base-load   1,065  

Dresden

  Morris, IL   2     Uranium   Base-load   1,740  

LaSalle

  Seneca, IL   2     Uranium   Base-load   2,288  

Limerick

  Limerick Twp., PA   2     Uranium   Base-load   2,293  

Oyster Creek

  Forked River, NJ   1     Uranium   Base-load   625  

Peach Bottom

  Peach Bottom Twp., PA   2   50   Uranium   Base-load   1,145 (e) 

Quad Cities

  Cordova, IL   2   75   Uranium   Base-load   1,317 (e) 

Salem

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

Three Mile Island

  Londonderry Twp, PA   1     Uranium   Base-load   837  
               
            17,009  

Fossil (Steam Turbines)

         

Conemaugh

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

Cromby 1

  Phoenixville, PA   1     Coal   Intermediate   144 (f) 

Cromby 2

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

Eddystone 1, 2

  Eddystone, PA   2     Coal   Intermediate   588 (f) 

Eddystone 3, 4

  Eddystone, PA   2     Oil/Gas   Intermediate   760  

Fairless Hills

  Falls Twp, PA   2     Landfill Gas   Peaking   60  

Handley 4, 5

  Fort Worth, TX   2     Gas   Peaking   870  

Handley 3

  Fort Worth, TX   1     Gas   Intermediate   395  

Keystone

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

Mountain
Creek 6, 7

  Dallas, TX   2     Gas   Peaking   240  

Mountain Creek 8

  Dallas, TX   1     Gas   Intermediate   565  

Schuylkill

  Philadelphia, PA   1     Oil   Peaking   166  

Wyman

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

 

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Station

 

Location

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

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

Fossil (Combustion Turbines)

         

Chester

  Chester, PA   3     Oil   Peaking   39  

Croydon

  Bristol Twp., PA   8     Oil   Peaking   391  

Delaware

  Philadelphia, PA   4     Oil   Peaking   56  

Eddystone

  Eddystone, PA   4     Oil   Peaking   60  

Falls

  Falls Twp., PA   3     Oil   Peaking   51  

Framingham

  Framingham, MA   3     Oil   Peaking   29  

LaPorte

  Laporte, TX   4     Gas   Peaking   152  

Medway

  West Medway, MA   3     Oil/Gas   Peaking   105  

Moser

  Lower Pottsgrove Twp., PA   3     Oil   Peaking   51  

New Boston

  South Boston, MA   1     Oil   Peaking   12  

Pennsbury

  Falls Twp., PA   2     Landfill Gas   Peaking   6  

Richmond

  Philadelphia, PA   2     Oil   Peaking   96  

Salem

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

Schuylkill

  Philadelphia, PA   2     Oil   Peaking   30  

Southeast Chicago

  Chicago, IL   8     Gas   Peaking   296  

Southwark

  Philadelphia, PA   4     Oil   Peaking   52  
               
            1,442  

Fossil (Internal Combustion/Diesel)

         

Conemaugh

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

Cromby

  Phoenixville, PA   1     Oil   Peaking   3  

Delaware

  Philadelphia, PA   1     Oil   Peaking   3  

Keystone

  Shelocta, PA   4   20.99   Oil   Peaking   2 (e) 

Schuylkill

  Philadelphia, PA   1     Oil   Peaking   3  
               
            13  

Hydroelectric and Renewable

         

City Solar

  Chicago, IL   n.a.     Solar   Base-load   10 (g) 

Conowingo

  Harford Co., MD   11     Hydroelectric   Base-load   572  

Muddy Run

  Lancaster, PA   8     Hydroelectric   Intermediate   1,070  
               
            1,652  
                 

Total

    124         24,850  
                 

 

(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, diesels and pumped-storage hydroelectric equipment normally used during the maximum load periods.
(c) For nuclear stations capacity reflects the annual mean rating. All other stations reflect a summer rating.
(d) All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.
(e) Net generation capacity is stated at proportionate ownership share.
(f) On December 2, 2009, Generation announced its intention to permanently retire four of its fossil-fired generating units effective May 31, 2011. Eddystone Generating Station Unit1 and Unit 2 and Cromby Generating Station Unit 1 are coal-fired units and Cromby Generating Station Unit 2 operates on either natural gas or fuel oil.
(g) Table represents total expected capacity upon project completion. City Solar is 82% complete as of December 31, 2009.

 

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 and generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

 

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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, 2009 were as follows:

 

     

Voltage (Volts)

  

Circuit Miles

     
  

765,000

   90   
  

345,000

   2,634   
  

138,000

   2,890   
  

69,000

   149   

 

ComEd’s electric distribution system includes 34,872 circuit miles of overhead lines and 29,765 cable 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 portion of its transmission rights of way 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.

 

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Transmission and Distribution

 

PECO’s higher voltage electric transmission lines owned and in service at December 31, 2009 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 500,000 voltage lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500,000 voltage lines located in Delaware and New Jersey.

 

PECO’s electric distribution system includes 12,971 circuit miles of overhead lines and 15,788 cable miles of underground lines.

 

Gas

 

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2009:

 

     Pipeline Miles

Transportation

   31

Distribution

   6,703

Service piping

   5,707
    

Total

   12,441
    

 

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 Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25 mmcf/day. In addition, PECO owns 29 natural gas city gate stations 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.

 

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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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

Exelon, Generation, ComEd and PECO

 

None.

 

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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 29, 2010, there were 659,895,066 shares of common stock outstanding and approximately 135,286 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:

 

     2009    2008
     Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter
   Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter

High price

   $ 51.98    $ 54.47    $ 51.46    $ 58.98    $ 63.84    $ 92.13    $ 91.84    $ 87.25

Low price

     45.90      47.30      44.24      38.41      41.23      60.00      81.00      70.00

Close

     48.87      49.62      50.12      45.39      55.61      62.62      89.96      81.27

Dividends

     0.525      0.525      0.525      0.525      0.525      0.500      0.500      0.500

 

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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 Corporation common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index for the period 2005 through 2009.

 

This performance chart assumes:

 

   

$100 invested on December 31, 2004 in Exelon Corporation 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 29, 2010, Exelon held the entire membership interest in Generation.

 

ComEd

 

As of January 29, 2010, there were 127,016,519 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 29, 2010, in addition to Exelon, there were 252 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 29, 2010, 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 financings arranged through ComEd Financing III that it 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.

 

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, 2009, such capital was $2.7 billion and amounted to about 32 times the liquidating value of the outstanding preferred securities of $87 million.

 

PECO may 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.

 

At December 31, 2009, Exelon had retained earnings of $8,134 million, including Generation’s undistributed earnings of $2,169 million, ComEd’s retained earnings of $304 million consisting of retained earnings appropriated for future dividends of $1,943 million, partially offset by $1,639 million of unappropriated retained deficits and PECO’s retained earnings of $426 million.

 

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The following table sets forth Exelon’s quarterly cash dividends per share paid during 2009 and 2008:

 

     2009    2008

(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    $ 0.500    $ 0.500    $ 0.500

 

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

 

     2009    2008(a)

(in millions)

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

Generation

   $ 475    $ 1,126    $ 396    $ 279    $ 301    $ 253    $ 302    $ 689

ComEd

     60      60      60      60      —        —        —        —  

PECO

     65      93      67      87      98      146      97      139

 

(a) During 2008, ComEd did not pay a dividend in order to manage cash flows and its capital structure.

 

On January 26, 2010, the Exelon Board of Directors declared a regular quarterly dividend of $0.525 per share on Exelon’s common stock. The dividend is payable on March 10, 2010, to shareholders of record of Exelon at the end of the day on February 16, 2010.

 

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations included in ITEM 7 of this Report on Form 10-K.

 

    For the Years Ended December 31,  

in millions, except for per share data

  2009   2008   2007   2006   2005  

Statement of Operations data:

         

Operating revenues

  $ 17,318   $ 18,859   $ 18,916   $ 15,655   $ 15,357  

Operating income

    4,750     5,299     4,668     3,521     2,724  

Income from continuing operations

  $ 2,706   $ 2,717   $ 2,726   $ 1,590   $ 951  

Income (loss) from discontinued operations

    1     20     10     2     14  

Income before cumulative effect of changes in accounting principles

    2,707     2,737     2,736     1,592     965  

Cumulative effect of changes in accounting principles (net of income taxes)

    —       —       —       —       (42
                               

Net income (a)

  $ 2,707   $ 2,737   $ 2,736   $ 1,592   $ 923  
                               

Earnings per average common share (diluted):

         

Income from continuing operations

  $ 4.09   $ 4.10   $ 4.03   $ 2.35   $ 1.40  

Income (loss) from discontinued operations

    —       0.03     0.02     —       0.02  

Cumulative effect of changes in accounting principles (net of income taxes)

    —       —       —       —       (0.06
                               

Net income

  $ 4.09   $ 4.13   $ 4.05   $ 2.35   $ 1.36  
                               

Dividends per common share

  $ 2.10   $ 2.03   $ 1.76   $ 1.60   $ 1.60  
                               

Average shares of common stock outstanding—diluted

    662     662     676     676     676  
                               

 

(a) The changes between 2007 and 2006; and 2006 and 2005 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

 

    December 31,

In millions

  2009   2008 (c)   2007 (b)(c)   2006 (b)(c)   2005 (b)(c)

Balance Sheet data:

         

Current assets

  $ 5,441   $ 5,130   $ 4,416   $ 4,130   $ 3,808

Property, plant and equipment, net

    27,341     25,813     24,153     22,775     21,981

Noncurrent regulatory assets

    4,872     5,940     5,133     5,808     4,734

Goodwill (a)

    2,625     2,625     2,625     2,694     3,475

Other deferred debits and other assets

    8,901     8,038     8,760     7,933     7,858
                             

Total assets

  $ 49,180   $ 47,546   $ 45,087   $ 43,340   $ 41,856
                             

Current liabilities

  $ 4,238   $ 3,811   $ 5,466   $ 4,871   $ 5,759

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

    11,385     12,592     11,965     11,911     11,760

Noncurrent regulatory liabilities

    3,492     2,520     3,301     3,025     2,518

Other deferred credits and other liabilities

    17,338     17,489     14,131     13,439     12,606

Minority interest

    —       —       —       —       1

Preferred securities of subsidiary

    87     87     87     87     87

Shareholders’ equity

    12,640     11,047     10,137     10,007     9,125
                             

Total liabilities and shareholders’ equity

  $ 49,180   $ 47,546   $ 45,087   $ 43,340   $ 41,856
                             

 

(a) The changes between 2006 and 2005 were primarily due to the impact of the goodwill impairment charge of $776 million in 2006.

 

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(b) Exelon and Generation retrospectively reclassified certain assets and liabilities in accordance with the applicable authoritative guidance for offsetting amounts related to qualifying derivative contracts.
(c) Exelon and Generation 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. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further discussion.

 

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,  

in millions, except for per share data

   2009    2008    2007    2006    2005  

Statement of Operations data:

              

Operating revenues

   $ 9,703    $ 10,754    $ 10,749    $ 9,143    $ 9,046  

Operating income

     3,295      3,994      3,392      2,396      1,852  

Income from continuing operations

   $ 2,122    $ 2,258    $ 2,025    $ 1,403    $ 1,109  

Income (loss) from discontinued operations

     —        20      4      4      19  

Income before cumulative effect of changes in accounting principles

     2,122      2,278      2,029      1,407      1,128  

Cumulative effect of changes in accounting principles (net of income taxes)

     —        —        —        —        (30
                                    

Net income

   $ 2,122    $ 2,278    $ 2,029    $ 1,407    $ 1,098  
                                    
     December 31,  

in millions

   2009    2008 (a)    2007 (a,b)    2006 (a,b)    2005 (a,b)  

Balance Sheet data:

              

Current assets

   $ 3,360    $ 3,486    $ 2,160    $ 2,571    $ 2,211  

Property, plant and equipment, net

     9,809      8,907      8,043      7,514      7,464  

Deferred debits and other assets

     9,237      7,691      8,044      7,845      7,108  
                                    

Total assets

   $ 22,406    $ 20,084    $ 18,247    $ 17,930    $ 16,783  
                                    

Current liabilities

   $ 2,262    $ 2,168    $ 1,917    $ 1,990    $ 2,596  

Long-term debt

     2,967      2,502      2,513      1,778      1,788  

Deferred credits and other liabilities

     10,385      8,848      9,447      8,678      8,417  

Minority interest

     2      1      1      1      2  

Member’s equity

     6,790      6,565      4,369      5,483      3,980  
                                    

Total liabilities and member’s equity

   $ 22,406    $ 20,084    $ 18,247    $ 17,930    $ 16,783  
                                    

 

(a) Exelon and 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. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further discussion.
(b) Exelon and 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,  

in millions, except for per share data

   2009    2008    2007    2006     2005  

Statement of Operations data:

             

Operating revenues

   $ 5,774    $ 6,136    $ 6,104    $ 6,101     $ 6,264  

Operating income (loss)

     843      667      512      555       (12

Income (loss) before cumulative effect of changes in accounting principles

   $ 374    $ 201    $ 165    $ (112   $ (676

Cumulative effect of a change in accounting principle (net of income taxes)

     —        —        —        —          (9
                                     

Net income (loss) (a)

   $ 374    $ 201    $ 165    $ (112   $ (685
                                     

 

(a) The changes between 2007 and 2006 and 2006 and 2005 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

 

     December 31,

in millions

   2009    2008    2007    2006    2005

Balance Sheet data:

              

Current assets

   $ 1,579    $ 1,309    $ 1,241    $ 1,007    $ 1,024

Property, plant and equipment, net

     12,125      11,655      11,127      10,457      9,906

Goodwill (a)

     2,625      2,625      2,625      2,694      3,475

Noncurrent regulatory assets

     1,096      858      503      532      280

Other deferred debits and other assets

     3,272      2,790      3,880      3,084      2,806
                                  

Total assets

   $ 20,697    $ 19,237    $ 19,376    $ 17,774    $ 17,491
                                  

Current liabilities

   $ 1,597    $ 1,153    $ 1,712    $ 1,600    $ 2,308

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

     4,704      4,915      4,384      4,133      3,541

Noncurrent regulatory liabilities

     3,145      2,440      3,447      2,824      2,450

Other deferred credits and other liabilities

     4,369      3,994      3,305      2,919      2,796

Shareholders’ equity

     6,882      6,735      6,528      6,298      6,396
                                  

Total liabilities and shareholders’ equity

   $ 20,697    $ 19,237    $ 19,376    $ 17,774    $ 17,491
                                  

 

(a) The change between 2006 and 2005 was primarily due to the impact of the goodwill impairment charge of $776 million in 2006.

 

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,  

in millions, except for per share data

   2009    2008    2007    2006    2005  

Statement of Operations data:

              

Operating revenues

   $ 5,311    $ 5,567    $ 5,613    $ 5,168    $ 4,910  

Operating income

     697      699      947      866      1,049  

Income before cumulative effect of changes in accounting principles

   $ 353    $ 325    $ 507    $ 441    $ 520  

Cumulative effect of a change in accounting principle (net of income taxes)

     —        —        —        —        (3

Net income

     353      325      507      441      517  
                                    

Net income on common stock

   $ 349    $ 321    $ 503    $ 437    $ 513  
                                    
     December 31,  

in millions

   2009    2008    2007    2006    2005  

Balance Sheet data:

              

Current assets

   $ 1,006    $ 819    $ 800    $ 762    $ 795  

Property, plant and equipment, net

     5,297      5,074      4,842      4,651      4,471  

Noncurrent regulatory assets

     1,834      2,597      3,273      3,896      4,454  

Other deferred debits and other assets

     882      679      895      464      366  
                                    

Total assets

   $ 9,019    $ 9,169    $ 9,810    $ 9,773    $ 10,086  
                                    

Current liabilities

   $ 939    $ 981    $ 1,516    $ 978    $ 936  

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

     2,405      2,960      2,866      3,784      4,143  

Noncurrent regulatory liabilities

     317      49      250      151      68  

Other deferred credits and other liabilities

     2,706      2,910      3,068      3,051      3,235  

Preferred securities

     87      87      87      87      87  

Shareholders’ equity

     2,565      2,182      2,023      1,722      1,617  
                                    

Total liabilities and shareholders’ equity

   $ 9,019    $ 9,169    $ 9,810    $ 9,773    $ 10,086  
                                    

 

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Exelon

 

General

 

Exelon, a utility services holding company, operates through the following principal subsidiaries each of which is treated as an operating segment:

 

   

Generation, whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.

 

   

ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in northern Illinois, including the City of Chicago.

 

   

PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services 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 in the Pennsylvania counties surrounding the City of Philadelphia.

 

See Note 20 of the Combined Notes to Consolidated Financial Statements for segment information.

 

Through its business services subsidiary BSC, Exelon provides its subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable business segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

 

Exelon Corporation

 

Executive Overview

 

Financial Results. Exelon’s net income was $2,707 million in 2009 as compared to $2,737 million in 2008, and diluted earnings per average common share were $4.09 in 2009 as compared to $4.13 in 2008. All amounts presented below are before the impact of income tax.

 

Exelon’s 2009 results were significantly affected by lower revenue net of purchased power and fuel expense at Generation of $411 million. This decrease was primarily due to reduced net mark-to-market gains from its hedging activities of $271 million and unfavorable portfolio and market conditions of $206 million. Additionally, Generation experienced higher nuclear fuel costs of $74 million. Partially offsetting these decreases were lower costs associated with the Illinois Settlement of $123 million.

 

ComEd experienced higher revenue net of purchased power expense of $155 million despite unfavorable weather conditions and reduced load. Distribution pricing increased ComEd’s operating revenues by $214 million primarily due to the ICC’s September 2008 order in the 2007 distribution rate case. This increase was partially offset by the impact of current economic conditions and unfavorable weather, which reduced ComEd’s load resulting in lower revenue net of purchased power expense of $40 million and $45 million, respectively.

 

PECO had a slight increase of $16 million in its revenue net of purchased power and fuel expense primarily due to increased gas distribution rates effective January 1, 2009 resulting from the settlement of 2008 rate case, which provided $77 million of additional revenues in 2009. PECO’s increased revenues also reflected the impact of lower electric distribution rates in 2008 of $22 million primarily due

 

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to the refund of the 2007 PURTA settlement (which was completely offset in charges recorded in taxes other than income). Similar to ComEd, these increases were partially offset by the impact of current economic conditions and unfavorable weather, which reduced PECO’s load resulting in lower revenue net of purchased power and fuel expense of $69 million and $21 million, respectively.

 

Exelon’s 2009 results were also affected by higher operating and maintenance expense at Generation. In March 2009, Generation re-evaluated the fair value of the Handley and Mountain Creek stations due to the continued decline in forward energy prices, which resulted in a $223 million impairment charge. In December 2009, Generation announced that it had notified PJM of its intention to permanently retire four fossil-fired generation units in Pennsylvania because they are no longer economic to operate and are not required to meet demand for electricity in the region. In connection with the announced retirements, Generation recorded a charge of $24 million related to exit costs as well as $32 million of accelerated depreciation.

 

Additionally, Exelon’s pension and other postretirement benefits expense increased by $160 million in 2009 due to lower than expected pension and postretirement plan asset returns in 2008. There was also a scheduled increase in CTC amortization expense at PECO of $90 million in accordance with its 1998 restructuring settlement and increased depreciation of $69 million across the Registrants due to ongoing capital expenditures.

 

In response to current market and economic conditions, Exelon implemented a cost savings program in 2009. This initiative included job reductions, for which Exelon recorded a $34 million charge related to severance expenses, and a $350 million discretionary contribution to Exelon’s largest pension fund, which is expected to reduce pension expense over the next ten years. PECO generated additional cost savings through enhancements to credit processes and increased collection and termination activities initiated in 2008, which reduced the allowance for uncollectible accounts expense by $97 million. In addition, ComEd’s and PECO’s incremental storm-related costs decreased by $40 million and $9 million, respectively.

 

Exelon’s interest expense decreased by $140 million primarily due to lower outstanding debt at ComEd and PECO and lower interest rates on Generation’s SNF obligation. Additionally, Exelon was able to capitalize on favorable capital market conditions in its refinancing of $1.2 billion of debt at Exelon and Generation originally scheduled to mature in 2011. Although this debt offering resulted in $120 million in debt extinguishment costs, it decreased Exelon’s average cost of debt while also extending the maturities of the debt.

 

Exelon’s 2009 results were also significantly affected by NDT realized and unrealized gains of $256 million in 2009 compared to realized and unrealized losses of $308 million in 2008 for the former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units (Non-Regulatory Agreement Units) as a result of improved market performance.

 

Finally, Exelon reassessed anticipated apportionment of its income, resulting in a change in state deferred income tax rates, and ComEd remeasured income tax uncertainties related to its 1999 sale of fossil generating assets. These two actions resulted in an aggregate non cash gain of $83 million.

 

For further detail regarding 2009 Financial Results, including explanation of non-GAAP measures, see the discussions of Results of Operations by Segment below.

 

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Outlook for 2010 and Beyond.

 

Economic and Market Conditions

 

   

Although financial markets have been relatively stable since last summer, manufacturing has remained weak and unemployment rates are still high. As a result, Exelon continues to be challenged by current economic conditions. The demand for electricity has been lower in the ComEd and PECO service territories, meaning relatively fewer retail sales in both areas than in previous years. Lower demand and other factors associated with the global slowdown in economic activity have caused oil, coal and natural gas prices to fall, and have also depressed wholesale electricity prices and therefore led to lower margins for Exelon’s wholesale generation fleet. With respect to natural gas in particular, the price of which is generally the most closely correlated to the price of electricity, the reduction has been significant. A fundamentally oversupplied natural gas market has resulted at times in prices below $3 per million British Thermal Units. Additionally, factors other than the weak global economy have contributed to lower natural gas prices. In particular, recent technological innovation has enabled the extraction of natural gas from North America’s vast shale formations at a cost that the markets can support even in a lower price environment.

 

       Exelon’s existing hedging policies are intended to reduce price volatility and maintain financial discipline. Although Exelon’s hedging policies have helped protect Exelon’s earnings as markets have declined, a period of prolonged depressed electricity prices would adversely impact Exelon’s and Generation’s results of operations in the future. Further discussion of commodity price risk is included in ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

       The volatility in the economy could affect the Registrants’ business. The Registrants have continued to assess the impact, if any, of market developments on their respective financial condition, including access to liquidity, counterparty creditworthiness, and the value of investments and other assets. See PART I. ITEM 1A. Risk Factors for information regarding the effects of continued uncertainty in the capital and credit markets or significant bank failures.

 

New Growth Opportunities

 

   

Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will generate between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.5 billion, as measured in current costs. 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 one quarter of the planned uprates, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Dresden, LaSalle and Quad Cities plants in Illinois. The remainder of uprate MW will come from additional projects across Generation’s nuclear fleet beginning in 2010 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates have 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.

 

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PECO plans to implement Smart Meter and Smart Grid technologies for all customers within their service territory to comply with Act 129. PECO plans to spend approximately $650 million on Smart Meter and Smart Grid investments, which is expected to be recovered with a return on investment from customers through regulated rates. In October 2009, the DOE announced its intent to award PECO $200 million in the ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. PECO will deduct any costs paid with DOE funds from amounts recoverable from customers. The new infrastructure will provide the basis for the communications network and information systems to integrate customer energy usage with utility operations, enabling two-way communication. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full grant on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 meters within three years and accelerating universal smart meter deployment from 15 years to 10 years. In addition, PECO may have additional costs associated with the replacement of gas meters and the wind-down of its legacy automated meter reading system.

 

       In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers. ComEd expects to have the program fully implemented in early summer 2010. The total anticipated cost of the pilot program is approximately $69 million. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of potential full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. See Note 2 of the Combined Notes to the Financial Statements for more information.

 

   

In the third quarter of 2009, Exelon established Exelon Transmission, which is a new venture that will seek to capitalize on the growing national market for new transmission lines. Exelon Transmission enters a market in which U.S. companies are projected to spend $60-$100 billion on transmission development projects by 2020. New transmission projects have the potential to reduce congestion, improve reliability, and facilitate movement of renewable energy, such as wind and solar, to population centers where it is needed most. Exelon will leverage existing members of management for the initial phases of the project. Exelon Transmission’s portfolio will evolve over time and may include projects with both traditional, regulated profiles as well as more competitive, market-based investments. Exelon expects to provide $10 million in funding to Exelon Transmission in 2010. Additional expenditures will be determined on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

 

Liquidity and Cost Management

 

   

Exelon is subject to significant ongoing cost pressures during these challenging economic times. Exelon is committed to operating its businesses responsibly and managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Exelon is also committed to an ongoing strategy to make itself more effective, efficient and innovative. In 2009, Exelon launched a company-wide cost management initiative, which combines short-term actions with long-term change. In the short-term, Exelon realized cost savings of approximately $200 million in 2009 over 2008, primarily as a result of the elimination of 500 positions within BSC and ComEd, productivity improvements and stringent controls on supply spending, contracting and overtime costs. Exelon is committed to maintaining a cost control focus and expects to largely offset increasing pension and benefits expense and general inflation in 2010 with additional cost savings, including freezing executive salaries and reducing employee benefits. With regard to long-term changes, Exelon is analyzing cost trends over the past five years to identify future cost savings opportunities and implementing more planning and performance-measurement tools that allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.

 

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The Registrants’ credit facilities largely extend through October 2012 for Exelon, Generation and PECO and February 2011 for ComEd. These credit facilities currently provide sufficient liquidity to the Registrants. Additionally, upon maturity of these credit facilities, the Registrants may not be able to renew or replace these existing facilities at current terms or commitment levels from banks. Consequently, the Registrants may face increased costs for liquidity needs and may choose to establish alternative liquidity sources to supply the balance of their needs beginning in 2010 for ComEd and in 2011 for Exelon, Generation and PECO.

 

Regulatory Matters

 

   

In July 2009, comprehensive legislation was enacted into law in Illinois which provides public utility companies the ability to bill or refund customers for the difference between the company’s annual uncollectible expense and amounts collected in rates through a rider mechanism. The legislation allows a public utility company to bill customers for under-collections of accounts starting with 2008 and prospectively. ComEd under-collected approximately $26 million during 2008 and approximately $44 million during 2009. On February 2, 2010, the ICC issued an order approving ComEd’s proposed tariffs for collecting the increases or decreases in uncollectible accounts expense, with minor modifications. With the ICC’s approval of the tariff, ComEd will begin collecting past due amounts in April 2010. ComEd will record the $70 million benefit in the first quarter of 2010. ComEd is also required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund to assist low-income residential customers through the forgiveness of a portion of past-due amounts.

 

   

During 2009, PECO, in accordance with its PAPUC-approved DSP Program, conducted two competitive procurements and entered into contracts with various counterparties, which included Generation, to procure electric supply for the residential, small commercial and medium commercial procurement classes beginning in 2011 in preparation for the expiration of its electric generation rate caps and its PPA with Generation on December 31, 2010. PECO will procure additional electric supply through seven more procurements of full requirements and forward purchase energy block contracts of varying lengths in accordance with the plan approved by the PAPUC. PECO has also been engaged in regulatory proceedings including Rate Mitigation Plans, Energy Efficiency and Conservation Plan and other regulatory filings to comply with the requirements of Act 129.

 

       Although these proceedings support competitive, market-based procurement during the 29-month term of the approved DSP Program, elected officials in Pennsylvania have suggested rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate relief programs that could have a significant impact on PECO and Generation.

 

   

The Pennsylvania Legislature is currently considering HB 80, which, if enacted into law, would increase the minimum required percentage of electric energy to be procured from alternative energy resources in Pennsylvania, expand the solar purchase and sale requirements and would incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource.

 

       See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for further detail related to these matters.

 

Environmental Legislation

 

   

Exelon supports the passage of comprehensive climate change legislation that balances the need to protect consumers, business and the economy with the urgent need to reduce GHG

 

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emissions in the United States. In June 2009, the U.S. House of Representatives passed H.R. 2454. Among its various components, the bill proposes mandatory, economy-wide GHG reduction targets and goals that would be achieved via a Federal emissions cap-and-trade program. If enacted, H.R. 2454 is expected to increase wholesale power prices as generating units reflect the price of carbon emission permits and the cost of emission reduction technology in their bids to supply energy to wholesale markets in order to recover their costs of compliance with carbon regulation. Due to its overall low-carbon generation portfolio, under the provisions of H.R. 2454, Exelon expects that its operating revenues would increase significantly. In September 2009, the U.S. Senate introduced its version of climate change legislation that is similar to H.R. 2454, but does not yet provide specific details regarding allowance allocations. Any bill passed by the U.S. Senate would need to be reconciled with H.R. 2454, approved by both the U.S. House of Representatives and the U.S. Senate, and signed by President Obama before becoming law.

 

   

Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. This goal was achieved by December 31, 2008 through Exelon’s planned GHG management efforts, including the previous closure of older, inefficient fossil power plants, reduced leakage of SF6, increased use of renewable energy and its current energy efficiency initiatives. In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). See Item 1. General Business for further discussion of Exelon’s voluntary GHG emissions reductions.

 

       See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

 

Healthcare Reform Legislation

 

   

In 2009, the U.S. House of Representatives and the U.S. Senate each passed its own version of healthcare reform bills that would fundamentally change the nation’s healthcare system. Due to the uncertainty as to the final outcome of Federal healthcare reform legislation, the Registrants are unable to estimate the effects on their respective results of operations, cash flows or financial positions.

 

Competitive Markets

 

   

Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2010 and 2011. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of December 31, 2009, the percentage of expected generation hedged was 91%—94%, 69%—72% and 37%—40% for 2010, 2011 and 2012, 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. Generation has been and will continue to be proactive in using hedging strategies to mitigate this price risk in subsequent years as well. PECO has transferred substantially all of its commodity price risk

 

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related to its procurement of electricity to Generation through a PPA that expires on December 31, 2010. Since PECO entered into its PPA with Generation, market prices for energy have generally been higher than the generation rates PECO has paid for purchased power, which represents the rates paid by PECO customers. Generation’s margins on its other sales have therefore generally been higher. The expiration of the PPA with PECO at the end of 2010 will likely result in increases in margins earned by Generation beginning in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA. While Generation’s three year ratable hedging program considers the expiration of the PPA the ultimate impact of entering into new power supply contracts will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC. Both PECO and ComEd mitigate exposure to commodity price risk through the recovery of procurement costs from retail customers.

 

   

Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 56% of Generation’s uranium concentrate requirements from 2010 through 2014 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with certain commodity price exposures.

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions within its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committees of the Exelon, ComEd and PECO Boards of Directors. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

 

Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

 

Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with the authoritative guidance for AROs.

 

The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses a probability-weighted, discounted cash flow model that considers multiple outcome scenarios based upon significant estimates and assumptions embedded in the following:

 

Decommissioning Cost Studies. Generation uses decommissioning cost studies on a unit-by-unit basis to provide a marketplace assessment of the costs and timing of decommissioning

 

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activities, which are validated by comparison to current decommissioning projects within its industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years.

 

Cost Escalation Studies. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the decommissioning period for each of the units. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. Cost escalation studies are updated on an annual basis.

 

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost, decommissioning alternatives and timing scenarios on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of actual costs plus 20% (high-cost scenario) or minus 15% (low-cost scenario) over the base cost scenario. Probabilities assigned to decommissioning alternatives assess the likelihood of performing DECON (a method of decommissioning in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use shortly after the cessation of operations), Delayed DECON (similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of decommissioning activities) or SAFSTOR (a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60 years after cessation of operations) procedures. Probabilities assigned to the timing scenarios incorporate the likelihood of continued operation through current license lives or through anticipated license renewals. Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal, which Generation currently assumes will begin in 2020, based on the DOE’s most recent indication. For more information regarding the estimated date that DOE will begin accepting SNF, see Note 12 of the Combined Notes to Consolidated Financial Statements.

 

Discount Rates. The probability-weighted estimated future cash flows using these various scenarios are discounted using credit-adjusted, risk-free rates applicable to the various businesses in which each of the nuclear units originally operated.

 

Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation. The following table illustrates the effects of changing certain ARO assumptions, discussed above, while holding all other assumptions constant (dollars in millions):

 

Change in ARO Assumption

   Increase to
ARO at
December 31, 2009

Cost escalation studies

  

Uniform increase in escalation rates of 25 basis points

   $ 364

Probabilistic cash flow models

  

Increase the likelihood of the high-cost scenario by 10 percentage points and decrease the likelihood of the low-cost scenario by 10 percentage points

   $ 126

Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points

   $ 231

Increase the likelihood of operating through current license lives by 10 percentage points and decrease the likelihood of operating through anticipated license renewals by 10 percentage points

   $ 305

 

If the estimated date for DOE acceptance of SNF were to be extended to 2030, Generation’s aggregate nuclear decommissioning obligation would be reduced by an immaterial amount.

 

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Under the authoritative guidance, the nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions or the expected timing or estimated amount of the future undiscounted cash flows required to decommission the nuclear plants. For more information regarding accounting for nuclear decommissioning obligations, see Notes 1 and 11 of the Combined Notes to Consolidated Financial Statements.

 

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

 

The NDT fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the NDTs. These policies restrict the NDT funds from holding alternative investments and limit the NDT funds’ exposures to investments in highly illiquid markets. On January 1, 2008, in order to align the accounting treatment of changes in the fair value of NDT fund investments in both an unrealized gain and an unrealized loss position, Generation elected the irrevocable option to measure financial assets and liabilities at fair value with changes in fair value recognized in earnings with respect to these investments. Therefore, the investments are carried at fair value with all changes in fair value being recognized through the statement of operations. See Notes 7 and 11 of the Combined Notes to Consolidated Financial Statements for further discussion on the NDT funds.

 

Asset Impairments (Exelon, Generation, ComEd and PECO)

 

Goodwill (Exelon and ComEd)

 

Exelon and ComEd have goodwill relating to the acquisition of ComEd in 2000 under the PECO/Unicom Merger. Under the provisions of the authoritative guidance for goodwill, Exelon and ComEd perform assessments for impairment of their goodwill at least annually or more frequently if an event occurs, such as a significant negative regulatory outcome, or circumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. The impairment assessment is performed using a two-step, fair value based test. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. In general, in applying the second step, fair value increases to assets and/or fair value decreases to liabilities would increase the size of any impairment. For example, a decrease in the fair value of ComEd’s debt would increase the size of any impairment and vice versa. Application of the goodwill impairment test requires management judgment, including the identification of reporting units, assigning assets, liabilities and goodwill to reporting units, determining the fair value of the reporting unit and, in applying the second step (if needed), determining the fair value of specific assets and liabilities of the reporting entity. See Note 6 of the Combined Notes to Consolidated Financial Statements for additional information.

 

The FASB’s fair value measurement and disclosure guidance for all nonrecurring fair value measurements of nonfinancial assets and liabilities, including goodwill, was effective for the Registrants as of January 1, 2009. This authoritative guidance clarified that fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. As a result, Exelon and ComEd now estimate the fair value of the ComEd reporting unit using a weighted combination of a discounted cash flow analysis and a market multiples analysis instead of the expected cash flow approach used in 2008 and prior years. The discounted cash flow analysis relies on a single scenario reflecting “base case” or

 

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“best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include ComEd’s capital structure, discount and growth rates, utility sector market performance, operating and capital expenditure requirements, fair value of debt, the selection of comparable companies and recent transactions. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiples analysis.

 

The regulatory environment has provided more certainty related to ComEd’s future cash flows. Although financial markets have stabilized over the past year, current economic conditions continue to impact the market-related assumptions used in the November 1, 2009 annual assessment. While ComEd did not recognize an impairment in 2009, deterioration of the market-related factors used in the impairment review could potentially result in a future impairment loss of ComEd’s goodwill, which could be material. If any combination of changes to significant assumptions resulted in a 5% reduction in fair value as of November 1, 2009, ComEd still would have passed the first step of the goodwill assessment.

 

Long-lived Assets (Exelon, Generation, ComEd and PECO)

 

Exelon, Generation, ComEd and PECO evaluate the carrying value of their long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets include general deterioration in the business climate, including current economic energy market conditions, deterioration in the physical condition or operating performance of the asset, specific regulatory disallowance or plans to dispose of a long-lived asset significantly before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power, costs of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the realizability of an asset and, thus, could have a significant effect on the consolidated financial statements. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets are largely independent of other groups of assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. For ComEd and PECO, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity. For ComEd the lowest level of independent cash flows is transmission and distribution and for PECO, the lowest level of independent cash flows is transmission, distribution and gas. Impairment may occur when the carrying value of the asset or asset group exceeds the associated future undiscounted cash flows. When the undiscounted cash flow analysis indicates that the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. An impairment is reported by the affected Registrant as a reduction to both the long-lived asset and current period earnings. See Note 4 of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Generation.

 

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Depreciable Lives of Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

 

The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. Depreciation of these assets is generally provided over their estimated service lives on a straight-line basis using the composite method. The estimation of service lives requires management judgment regarding the period of time that the assets will be in use. As circumstances warrant, the estimated service lives are reviewed to determine if any changes are needed. Depreciation rates incorporate assumptions on interim retirements based on actual historical retirement experience. To the extent interim retirement patterns change, this could have a significant impact on the amount of depreciation expense recorded in the income statement. Changes to depreciation estimates resulting from a change in the estimated end of service lives could have a significant impact on the amount of depreciation expense recorded in the income statement.

 

The estimated service lives of the nuclear generating facilities are based on the estimated useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses for all of Generation’s operating nuclear generating stations. While Generation has received license renewals for certain facilities, and has applied for or expects to apply for and obtain approval of license renewals for the remaining facilities, circumstances may arise that would prevent Generation from obtaining additional license renewals. Generation also periodically evaluates the estimated service lives of its fossil fuel generating facilities based on feasibility assessments as well as economic and capital requirements. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. A change in depreciation estimates resulting from Generation’s extension or reduction of the estimated service lives could have a significant effect on Generation’s results of operations.

 

ComEd is required to file a depreciation rate study at least every five years with the ICC. ComEd filed a depreciation rate study with the ICC in January 2009, which resulted in the implementation of new depreciation rates effective January 1, 2009.

 

PECO is required to file a depreciation rate study at least every five years with the PAPUC. In August 2005, PECO filed a depreciation rate study with the PAPUC for both its electric and gas assets, which resulted in the implementation of new depreciation rates effective March 2006.

 

Defined Benefit Pension and Other Postretirement Benefits (Exelon, Generation, ComEd and PECO)

 

Exelon sponsors defined benefit pension plans and postretirement benefit plans for substantially all Generation, ComEd, PECO, and Exelon Corporate employees. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and postretirement benefit plans.

 

The measurement of the plan obligations and costs associated with providing benefits under these plans involve several factors, including development of valuation assumptions and determining accounting elections. When developing the various assumptions that are required, Exelon considers historical information as well as future expectations. The measurement of benefit costs is affected by the actual rate of return on plan assets, and assumptions, including the long-term expected rate of return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, the long-term expected investment rate credited to employees of certain plans, the anticipated rate of increase of healthcare costs and the level of benefits provided to employees and retirees, among other factors. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. As required by the authoritative guidance, the impact of assumption changes on pension and other postretirement benefit

 

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obligations is generally recognized over the expected average remaining service period of the employees rather than immediately recognized in the income statement. Pension and postretirement benefit costs attributed to the operating companies are labor costs and ultimately allocated to projects within the operating companies, some of which are capitalized.

 

Pension and postretirement benefit plan assets include equity and fixed income securities held through funds as well as certain alternative investment classes. See Note 13 of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and other postretirement plan assets, including valuation techniques and classification in accordance with authoritative guidance under the fair value hierarchy.

 

Expected Rate of Return on Plan Assets. The long-term expected rate of return on plan assets assumption used in calculating pension costs was 8.50%, 8.75% and 8.75% for 2009, 2008 and 2007, respectively. The weighted average EROA assumption used in calculating other postretirement benefit costs was 8.10%, 7.80% and 7.85% in 2009, 2008 and 2007 respectively. The pension trust activity is non-taxable, while other postretirement benefit trust activity is partially taxable. The EROA is based on current asset allocations as described in Note 13 of the Combined Notes to Consolidated Financial Statements. A change in the asset allocation strategy could impact the EROA and related costs. Exelon will use an EROA of 8.50% and 7.83%, for estimating its 2010 pension costs and other postretirement benefit costs, respectively.

 

Exelon calculates the expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets, Exelon uses fair value to calculate the MRV.

 

Actual asset returns have a significant effect on the costs reported for the Exelon-sponsored pension and other postretirement benefit plans. The actual asset returns across the Registrant’s pension and other postretirement benefit plans for the year ended December 31, 2009 were approximately 21% compared to an expected long-term return assumption of 8.5% and 8.1%, respectively. Those return levels are expected to decrease 2010 and 2011 benefit costs as follows:

 

(dollars in millions)

   Decrease in 2010
Pension Cost
    Decrease in 2010
Postretirement
Benefit Cost
    Decrease in 2011
Pension Cost
    Decrease in 2011
Postretirement
Benefit Cost
 

2009 asset returns of 21%

   $ (28   $ (29   $ (27   $ (28

 

This information assumes that movements in asset returns occur absent changes to other actuarial assumptions, and does not consider any actions management may take, such as changes to the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential decrease in benefit costs set forth above. For example, decreases in actual discount rates, absent changes in other assumptions, increase pension and postretirement costs and obligations. Sensitivities of cost and obligations to key actuarial assumptions are discussed in further detail below.

 

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Discount Rate. The discount rate for determining both the pension and other postretirement benefit obligations was 5.83%, 6.09% and 6.20% at December 31, 2009, 2008 and 2007, respectively. At December 31, 2009, 2008 and 2007, the discount rate was determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefit obligations. The spot rates are used to discount the estimated distributions under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to select the discount rates.

 

The discount rate assumptions used to determine the obligation at year end will be used to determine the cost for the following year. Exelon will use a discount rate of 5.83% for estimating its 2010 pension costs and other postretirement benefit costs.

 

Healthcare Cost Trend Rate. Assumed healthcare cost trend rates also have a significant effect on the costs reported for Exelon’s other postretirement benefit plans. In determining the healthcare cost trend rate, Exelon reviews actual recent cost trends and projected future trends.

 

Sensitivity to Changes in Key Assumptions: The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):

 

Actuarial Assumption

  Change in
Assumption
  Pension    Other
Postretirement
Benefits
    Total  

Change in 2009 cost:

        

Discount rate

  (0.5)%   $ 44    $ 26     $ 70  

EROA

  (0.5)%     46      6       52  

Healthcare trend rate

  1.00%     —        49       49  
  (1.00)%     —        (40     (40
  Extend the year at
which the ultimate
healthcare trend rate of

5% is forecasted to be
reached by 5 years

    —        19       19  

Change in benefit obligation at December 31, 2009:

        

Discount rate

  (0.5)%     727      222       949  

EROA

  (0.5)%     —        —          —     

Healthcare trend rate

  1.00%     —        448       448  
  (1.00)%     —        (372     (372
  Extend the year at

which the ultimate
healthcare trend rate of
5% is forecasted to be
reached by 5 years

    —        152       152  

 

Average Remaining Service Period. For pension benefits, Exelon amortizes its unrecognized prior service costs and certain of its actuarial gains and losses, as applicable, based on participants’ average remaining service periods. For other postretirement benefits, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period related to eligibility age and amortizes its transition obligations and certain actuarial gains and losses over

 

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participants’ average remaining service period to expected retirement. The average remaining service period of defined benefit pension plan participants was 12.7 years, 12.8 years and 13.0 years for the years ended December 31, 2009, 2008 and 2007, respectively. The average remaining service period of postretirement benefit plan participants related to eligibility age was 6.8 years, 6.9 years and 6.9 years for the years ended December 31, 2009, 2008 and 2007, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.2 years, 9.4 years and 9.7 years for the years ended December 31, 2009, 2008 and 2007, respectively.

 

Regulatory Accounting (Exelon, ComEd and PECO)

 

Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with the authoritative guidance for accounting for certain types of regulations, which requires Exelon, ComEd, and PECO to reflect the effects of rate regulation in their financial statements. Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator will allow for future recovery through rates charged to customers. Regulatory liabilities represent revenues collected from customers in excess of prescribed recovery that must be refunded to customers through an adjustment of billing rates. Use of this guidance is applicable to utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable expectation that all costs will be recoverable from customers through rates. As of December 31, 2009, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria. If it is concluded in a future period that a separable portion of those operations no longer meets the criteria of this guidance, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of those operations, which 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 would be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2009, the extraordinary gain could have been as much as $1.7 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2009, the extraordinary charge could have been as much as $1.5 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an extraordinary gain or charge in an equal amount related to ComEd’s and PECO’s regulatory assets and liabilities in addition to a charge against OCI (before taxes) of up to $2.5 billion and $92 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 2, 6 and 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory issues, ComEd’s goodwill and the significant regulatory assets and liabilities of Exelon, ComEd and PECO, respectively.

 

For each regulatory jurisdiction in which they conduct business, Exelon, ComEd and PECO continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement. This assessment includes consideration of factors such as changes in applicable regulatory environments and recent rate orders, including for other regulated entities in the same jurisdiction. Furthermore, Exelon, ComEd and PECO make other judgments related to the financial statement impact of their regulatory environments, such as the types of adjustments to rate base that will be acceptable to regulatory bodies and the types of costs and the extent, if any, to which those costs will be recoverable through rates. Additionally, estimates are made in accordance with the authoritative guidance for contingencies, as to the amount of revenues billed under certain regulatory orders that will ultimately be refunded to customers upon finalization of the appropriate regulatory process. These assessments are based, to the extent possible, on past relevant

 

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experience with regulatory bodies, known circumstances specific to a particular matter, discussions held with the applicable regulatory body and other factors. If the assessments and estimates made by Exelon, ComEd and PECO are ultimately different than actual events, the impact on their results of operations, financial position, and cash flows could be material.

 

Accounting for Derivative Instruments (Exelon, Generation, ComEd and PECO)

 

The Registrants utilize derivative instruments to manage their exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases and other energy-related products marketed and purchased. Additionally, Generation enters into energy-related derivatives for proprietary trading purposes. ComEd has entered into contracts to procure energy, capacity and ancillary services. In addition, ComEd has a financial swap contract with Generation that extends into 2013. PECO has entered into derivative natural gas contracts to hedge its long-term price risk in the natural gas market. As part of the preparation for the expiration of the PPA with Generation at the end of 2010, PECO has entered into derivative contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program. ComEd and PECO do not enter into derivatives for proprietary trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

 

The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether or not a contract qualifies as a derivative under this guidance requires that management exercise significant judgment, including assessing the market liquidity as well as determining whether a contract has one or more underlyings and one or more notional amounts. Further, interpretive guidance related to the authoritative literature continues to evolve, including how it applies to energy and energy-related products. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance related to derivatives, could result in previously excluded contracts being subject to the provisions of the authoritative derivative guidance. Generation has determined that contracts to purchase uranium do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Generation begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Generation’s other derivative instruments. In this case, if market prices differ from the underlying prices of the contracts, Generation would be required to record a mark-to-market gain or loss, which may have a material impact to Exelon’s and Generation’s financial positions and results of operations.

 

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting and for energy-related derivatives entered for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings each period except for ComEd and PECO, in which changes in the fair value each period are recorded in a regulatory asset or liability.

 

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Normal Purchases and Normal Sales Exception. Determining whether a contract qualifies for the normal purchases and normal sales exception requires that management exercise judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal sales are recognized when the underlying physical transaction is completed. Contracts which qualify for the normal purchases and normal sales exception are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and price is not tied to an unrelated underlying derivative. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under the authoritative guidance, the transactions have been designated as normal purchases and normal sales and are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. The contracts that ComEd has entered into with Generation and other suppliers as part of the initial ComEd procurement auction and the subsequent RFP process, PECO’s full requirements fixed price contracts under the PAPUC-approved DSP program and all of PECO’s natural gas supply agreements that are derivatives, qualify for the normal purchases and normal sales exception. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the scope exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings at Generation or offset by a regulatory asset or liability at ComEd and PECO. Thereafter, future changes in fair value would be recorded in the balance sheet and recognized through earnings at Generation. Triggering events that could result in a contract’s loss of the normal purchase and normal sale designation, because it is no longer probable that the contract will result in physical delivery, include changes in business requirements, changes in counterparty credit and book-outs (financial settlements).

 

Commodity Contracts. Identification of a commodity contract as a qualifying cash flow hedge requires Generation to determine that the contract is in accordance with the RMP, the forecasted future transaction is probable and the hedging relationship between the commodity contract and the expected future purchase or sale of the commodity is expected to be highly effective at the initiation of the hedge and throughout the hedging relationship. Internal models that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a commodity contract designated as a hedge. Generation reassesses its cash flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are probable. When a contract does not meet the effective or probable criteria of the authoritative guidance, hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings at Generation or offset by a regulatory asset or liability at ComEd and PECO.

 

As a part of accounting for derivatives, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. In accordance with the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges are categorized in Level 2. These price quotations

 

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reflect the average of the bid-ask mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The Registrant’s non-exchange-based derivatives are predominately at liquid trading points. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of credit and nonperformance risk were not material to the financial statements.

 

Interest Rate Derivative Instruments. The Registrants may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. The Registrants use a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, as well as market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy.

 

See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 7 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

 

Taxation (Exelon, Generation, ComEd and PECO)

 

Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement in accordance with the authoritative guidance for accounting for uncertain tax positions. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Registrants’ consolidated financial statements.

 

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The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. The Registrants also assess their ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. The Registrants record valuation allowances for deferred tax assets when the Registrants conclude it is more likely than not such benefit will not be realized in future periods.

 

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, the Registrants’ forecasted financial condition and results of operations in future periods, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. While the Registrants believe the resulting tax balances as of December 31, 2009 and 2008 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.

 

Accounting for Contingencies (Exelon, Generation, ComEd and PECO)

 

In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record loss contingency amounts that are probable and reasonably estimable based upon available information. The amounts recorded may differ from the actual income or expense that occurs when the uncertainty is resolved. The estimates that the Registrants make in accounting for contingencies and the gains and losses that they record upon the ultimate resolution of these uncertainties could have a significant effect on their consolidated financial statements.

 

Environmental Costs

 

Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, changes in technology, regulations and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimate, could have a material effect on the Registrants’ results of operations, financial position and cash flows.

 

Other, Including Personal Injury Claims

 

The Registrants are self-insured for general liability, automotive liability, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Projecting future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible legislative measures in the United States, could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material effect on the Registrants’ results of operations, financial position and cash flows.

 

Allowance for Uncollectible Accounts (Exelon, Generation, ComEd and PECO)

 

The allowance for uncollectible accounts reflects the Registrants’ best estimates of probable losses on the accounts receivable balances. The allowance is based on known troubled accounts,

 

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historical experience and other currently available evidence. For ComEd and PECO, customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Customer accounts are written off consistent with approved regulatory guidelines. ComEd and PECO are each currently obligated to provide service to all electric customers within their respective franchised territories and are prohibited from terminating electric service to certain residential customers due to nonpayment during certain months of the year. ComEd’s and PECO’s provisions for uncollectible accounts will continue to be affected by changes in prices and economic conditions as well as changes in ICC and PAPUC regulations, respectively.

 

Revenue Recognition (Exelon, Generation, ComEd and PECO)

 

Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of Generation’s, ComEd’s and PECO’s retail energy sales to individual customers, however, is based on systematic readings of customer meters generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. Unbilled revenue is estimated each month based on daily customer usage measured by generation or gas throughput volume, estimated customer usage by class, estimated losses of energy during delivery to customers and applicable customer rates. Increases in volumes delivered to the utilities’ customers and favorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date would also have an effect on the estimated unbilled revenue; however, total operating revenues would remain materially unchanged.

 

The determination of Generation’s energy sales, excluding the retail business, is based on estimated amounts delivered as well as fixed quantity sales. At the end of each month, amounts of energy delivered to customers during the month are estimated and the corresponding unbilled revenue is recorded. Increases in volumes delivered to the wholesale customers in the period, as well as price, would increase unbilled revenue.

 

Results of Operations by Business Segment

 

The comparisons of operating results and other statistical information for the years ended December 31, 2009, 2008 and 2007 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

 

Net Income (Loss) from Continuing Operations by Business Segment

 

     2009     2008     Favorable
(unfavorable)
2009 vs. 2008
variance
    2007    Favorable
(unfavorable)
2008 vs. 2007
variance
 

Generation

   $ 2,122     $ 2,258     $ (136   $ 2,025    $ 233  

ComEd

     374       201       173       165      36  

PECO

     353       325       28       507      (182

Other (a)

     (143     (67     (76     29      (96
                                       

Total

   $ 2,706     $ 2,717     $ (11   $ 2,726    $ (9
                                       

 

(a) Other primarily includes corporate operations, BSC, investments in synthetic fuel-producing facilities and intersegment eliminations.

 

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Net Income (Loss) by Business Segment

 

     2009     2008     Favorable
(unfavorable)
2009 vs. 2008
variance
    2007    Favorable
(unfavorable)
2008 vs. 2007
variance
 

Generation

   $ 2,122     $ 2,278     $ (156   $ 2,029    $ 249  

ComEd

     374       201       173       165      36  

PECO

     353       325       28       507      (182

Other (a)

     (142     (67     (75     35      (102
                                       

Total

   $ 2,707     $ 2,737     $ (30   $ 2,736    $ 1  
                                       

 

(a) Other primarily includes corporate operations, BSC, investments in synthetic fuel-producing facilities and intersegment eliminations.

 

Results of Operations—Generation

 

     2009     2008     Favorable
(unfavorable)
2009 vs. 2008
variance
    2007     Favorable
(unfavorable)
2008 vs. 2007
variance
 

Operating revenues

   $ 9,703     $ 10,754     $ (1,051   $ 10,749     $ 5  

Purchased power and fuel expense

     2,932       3,572       640       4,451       879  
                                        

Revenue net of purchased power and fuel expense (a)

     6,771       7,182       (411     6,298       884  

Other operating expenses

          

Operating and maintenance

     2,938       2,717       (221     2,454       (263

Depreciation and amortization

     333       274       (59     267       (7

Taxes other than income

     205       197       (8     185       (12
                                        

Total other operating expenses

     3,476       3,188       (288     2,906       (282
                                        

Operating income

     3,295       3,994       (699     3,392       602  

Other income and deductions

          

Interest expense

     (113     (136     23       (161     25  

Equity in earnings (losses) of investments

     (3     (1     (2     1       (2

Other, net

     376       (469     845       155       (624
                                        

Total other income and deductions

     260       (606     866       (5     (601
                                        

Income from continuing operations before income taxes

     3,555       3,388       167       3,387       1  

Income taxes

     1,433       1,130       (303     1,362       232  
                                        

Income from continuing operations

     2,122       2,258       (136     2,025       233  

Income from discontinued operations, net of income taxes

     —          20       (20     4       16  
                                        

Net income

   $ 2,122     $ 2,278     $ (156   $ 2,029     $ 249  
                                        

 

(a) Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

 

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Net Income

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Generation’s 2009 results compared to 2008 were significantly affected by lower revenue net of purchased power and fuel expense primarily due to unfavorable portfolio and market conditions, including decreased net mark-to-market gains from its hedging activities, and revenue from certain long options in Generation’s proprietary trading portfolio recorded in 2008. Additionally, Generation’s revenue net of purchased power and fuel expense was affected by gains related to the settlement of uranium supply agreements in 2008 and higher nuclear fuel costs in 2009 due to rising nuclear fuel prices. The decrease in Generation’s revenues net of purchased power and fuel expense was partially offset by lower costs related to the Illinois Settlement.

 

Generation’s 2009 results compared to 2008 were further affected by higher operating and maintenance expenses. Higher operating and maintenance expenses were primarily due to a $223 million charge associated with the impairment of the Handley and Mountain Creek stations and costs associated with the announced shut-down of three coal-fired and one dual fossil-fired generation unit in Pennsylvania. These actions were a direct result of current and future expected market conditions. Market conditions also contributed to lower than expected pension and postretirement plan asset returns in 2008, which resulted in higher pension and other postretirement benefits expense in 2009. Higher operating and maintenance expenses were partially offset by the favorable results of Exelon’s companywide cost savings initiative and lower nuclear refueling outage costs.

 

Additionally, due to a significant rebound in the financial markets, Generation experienced strong performance in its NDT funds in 2009. As a result, Generation’s earnings improved as its NDTs of the Non-Regulatory Agreement Units had significant net realized and unrealized gains in 2009 compared to significant net realized and unrealized losses in 2008.

 

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Generation’s 2008 results were significantly affected by higher revenue net of purchased power and fuel expense compared to 2007 primarily due to favorable portfolio and market conditions, including increased net mark-to-market gains from its hedging activities, and revenue from certain long options in Generation’s proprietary trading portfolio recorded in 2008, which were primarily the result of favorable energy prices. Additionally, Generation’s revenue net of purchased power and fuel expense was affected by lower costs incurred in conjunction with the Illinois Settlement and the gain on the termination of the State Line Energy, L.L.C. (State Line) PPA in 2007.

 

Generation’s 2008 results compared to 2007 were further affected by higher operating and maintenance expenses. Higher operating and maintenance expenses included higher nuclear planned refueling outage costs and higher labor and contracting costs.

 

Additionally, due to a sharp decline in the financial markets, Generation’s NDTs of its Non-Regulatory Agreement Units had significant net realized and unrealized losses in 2008.

 

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Table of Contents

Operating Revenues

 

For the years ended December 31, 2009, 2008 and 2007, Generation’s sales were as follows:

 

Revenue

   2009     2008     2009 vs. 2008     2007     2008 vs. 2007  
       Variance     %
Change
      Variance     %
Change
 

Electric sales to affiliates

   $ 3,470     $ 3,588     $ (118   (3.3 )%    $ 3,537     $ 51     1.4

Wholesale and retail electric sales

     5,978       6,693       (715   (10.7 )%      6,834       (141   (2.1 )% 
                                            

Total electric sales revenue

     9,448       10,281       (833   (8.1 )%      10,371       (90   (0.9 )% 

Retail gas sales

     295       497       (202   (40.6 )%      449       48     10.7

Trading portfolio

     1       106       (105   (99.1 )%      43       63     146.5

Other operating revenue (a)

     (41     (130     89     68.5     (114     (16   (14.0 )% 
                                            

Total operating revenues

   $ 9,703     $ 10,754     $ (1,051   (9.8 )%    $ 10,749     $ 5     0.0
                                            

 

(a) Includes costs incurred for the Illinois Settlement and revenues relating to fossil fuel sales and decommissioning revenue from PECO during 2009, 2008 and 2007.

 

Sales (in GWh)

   2009    2008    2009 vs. 2008     2007    2008 vs. 2007  
         Variance     %
Change
       Variance     %
Change
 

Electric sales to affiliates

   58,643    64,652    (6,009   (9.3 )%    64,406    246     0.4

Wholesale and retail electric sales

   114,422    111,522    2,900     2.6   125,244    (13,722   (11.0 )%