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, 2007

 

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, Chicago and
Philadelphia

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 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 or a non-accelerated filer (as defined in Rule 12b-2 of the Act).

 

     Large Accelerated    Accelerated    Non-Accelerated

Exelon Corporation

   X      

Exelon Generation Company, LLC

         X

Commonwealth Edison Company

         X

PECO Energy Company

         X

 

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, 2007, was as follows:

 

Exelon Corporation Common Stock, without par value

   $ 48,917,819,593

Exelon Generation Company, LLC

   Not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

   No established market

PECO Energy Company Common Stock, without par value

   None

 

The number of shares outstanding of each registrant’s common stock as of January 31, 2008 was as follows:

 

Exelon Corporation Common Stock, without par value

   661,220,392

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

 

 

 


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TABLE OF CONTENTS

 

     Page No.

FILING FORMAT

   1

FORWARD-LOOKING STATEMENTS

   1

WHERE TO FIND MORE INFORMATION

   1

PART I

     
ITEM 1.   

BUSINESS

   2
  

General

   2
  

Exelon Generation Company, LLC

   3
  

Commonwealth Edison Company

   17
  

PECO Energy Company

   20
  

Employees

   25
  

Environmental Regulation

   26
  

Managing the Risks in the Business

   35
  

Executive Officers of the Registrants

   38
ITEM 1A.   

RISK FACTORS

   41
  

Exelon Corporation

   41
  

Exelon Generation Company, LLC

   46
  

Commonwealth Edison Company

   53
  

PECO Energy Company

   54
ITEM 1B.   

UNRESOLVED STAFF COMMENTS

   58
ITEM 2.   

PROPERTIES

   58
  

Exelon Generation Company, LLC

   58
  

Commonwealth Edison Company

   60
  

PECO Energy Company

   61
ITEM 3.   

LEGAL PROCEEDINGS

   62
  

Exelon Corporation

   62
  

Exelon Generation Company, LLC

   62
  

Commonwealth Edison Company

   62
  

PECO Energy Company

   62
ITEM 4.   

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   62

PART II

     
ITEM 5.   

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

   63
ITEM 6.   

SELECTED FINANCIAL DATA

   67
  

Exelon Corporation

   67
  

Exelon Generation Company, LLC

   68
  

Commonwealth Edison Company

   69
  

PECO Energy Company

   70
ITEM 7.   

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

   71
  

Exelon Corporation

   71
  

General

   71
  

Executive Overview

   71
  

Critical Accounting Policies and Estimates

   79
  

Results of Operations

   90
  

Liquidity and Capital Resources

   133
  

Exelon Generation Company, LLC

   166
  

Commonwealth Edison Company

   168

 

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     Page No.
  

PECO Energy Company

   170

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   156
  

Exelon Corporation

   156
  

Exelon Generation Company, LLC

   167
  

Commonwealth Edison Company

   169
  

PECO Energy Company

   171

ITEM 8.

  

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   172
  

Exelon Corporation

   172
  

Exelon Generation Company, LLC

   173
  

Commonwealth Edison Company

   174
  

PECO Energy Company

   175
  

Combined Notes to Consolidated Financial Statements

   204
  

1. Significant Accounting Policies

   204
  

2. Acquisitions and Dispositions

   221
  

3. Discontinued Operations

   223
  

4. Regulatory Issues

   224
  

5. Accounts Receivable

   237
  

6. Property, Plant and Equipment

   238
  

7. Jointly Owned Electric Utility Plant

   240
  

8. Intangible Assets

   240
  

9. Fair Value of Financial Assets and Liabilities

   243
  

10. Derivative Financial Instruments

   244
  

11. Debt and Credit Agreements

   250
  

12. Income Taxes

   258
  

13. Asset Retirement Obligations

   267
  

14. Spent Nuclear Fuel Obligation

   273
  

15. Retirement Benefits

   274
  

16. Preferred Securities

   286
  

17. Common Stock

   286
  

18. Earnings Per Share

   295
  

19. Commitments and Contingencies

   296
  

20. Supplemental Financial Information

   317
  

21. Segment Information

   333
  

22. Related Party Transactions

   335
  

23. Quarterly Data

   344
  

24. Subsequent Events

   346

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   347

ITEM 9A.

  

CONTROLS AND PROCEDURES

   347
  

Exelon Corporation

   347
  

Exelon Generation Company, LLC

   347
  

Commonwealth Edison Company

   347
  

PECO Energy Company

   347

ITEM 9B.

  

OTHER INFORMATION

   347
  

Exelon Corporation

   347

PART III

     

ITEM 10.

  

DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

   348
  

Exelon Corporation

   348
  

Exelon Generation Company, LLC

   348

 

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     Page No.
  

Commonwealth Edison Company

   349
  

PECO Energy Company

   350

ITEM 11.

  

EXECUTIVE COMPENSATION

   352

ITEM 12.

  

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

   405
  

Exelon Corporation

   405
  

Exelon Generation Company, LLC

   405
  

Commonwealth Edison Company

   406
  

PECO Energy Company

   405

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

   408

ITEM 14.

  

PRINCIPAL ACCOUNTING FEES AND SERVICES

   409
  

Exelon Corporation

   409
  

Exelon Generation Company, LLC

   410
  

Commonwealth Edison Company

   410
  

PECO Energy Company

   410

PART IV

     

ITEM 15.

  

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   412

SIGNATURES

   430
  

Exelon Corporation

   430
  

Exelon Generation Company, LLC

   431
  

Commonwealth Edison Company

   432
  

PECO Energy Company

   433

CERTIFICATION EXHIBITS

   434

 

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FILING FORMAT

 

This combined Form 10-K is being filed separately by Exelon Corporation (Exelon), Exelon Generation Company, LLC (Generation), Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) (collectively, the Registrants). 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 19 and (d) other factors discussed in filings with the United States Securities and Exchange Commission (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 Katherine K. Combs, Vice President 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 21 of the Combined Notes to Consolidated Financial Statements for further 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 sales 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 and wholesale sale of electricity and the provision of distribution and transmission 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.

 

Federal and State Regulation

 

The Registrants are subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). Illinois legislation enacted in August 2007 provides for the creation of the Illinois Power Agency (IPA). The IPA

 

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is authorized to design electric supply portfolio plans for electric utilities and administer a competitive procurement process for utilities to procure the electricity supply resources identified in the supply portfolio plans subject to the oversight of the ICC. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PAPUC). Generation, ComEd and PECO are public utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Under the Federal Power Act, FERC also has jurisdiction over third-party financings and certain holding company matters, including review of mergers, affiliate transactions, intercompany financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. Specific operations of the Registrants are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the Nuclear Regulatory Commission (NRC). For additional information about Federal and state restrictions on Exelon and its subsidiaries, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon.

 

Generation

 

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

 

At December 31, 2007, Generation owned generation assets with an aggregate net capacity of 24,808 MWs, including 16,969 MWs of nuclear capacity. In addition, Generation controlled another 7,524 MWs 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 power purchase agreement (PPA) with PECO and ICC-approved standardized supplier forward contracts with ComEd and Ameren Corporation (Ameren). 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, Michigan and Ohio. Generation’s retail business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low-margin nature of the business makes it important to service customers with higher volumes so as to manage costs.

 

The PPA between Generation and PECO expires at the end of 2010. Generation’s PPA with ComEd expired at the end of 2006. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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Generating Resources

 

At December 31, 2007, the generating resources of Generation consisted of the following:

 

Type of Capacity

   MWs

Owned generation assets (a)

  

Nuclear

   16,969

Fossil

   6,197

Hydroelectric

   1,642
    

Owned generation assets

   24,808

Long-term contracts (b)

   7,524
    

Total generating resources

   32,332
    

 

(a) See “Fuel” for sources of fuels used in electric generation.
(b) Long-term contracts range in duration up to 25 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 48% of capacity), the Mid-Atlantic region, which is comprised of Pennsylvania, New Jersey, Maryland and West Virginia (approximately 35% of capacity), the Southern region, which is comprised of Texas, Georgia and Oklahoma (approximately 16%), 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 with 16,969 MWs of capacity. Generation’s nuclear fleet plus its ownership interest in two generating units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC (PSEG Nuclear), generated 140,359 gigawatthours (GWhs), or approximately 93% of Generation’s total output, for the year ended December 31, 2007. For additional information regarding Generation’s electric generating capacity by station, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, an indirect, wholly owned subsidiary of Public Service Enterprise Group Incorporated (PSEG). AmerGen Energy Company, LLC (AmerGen), a wholly owned subsidiary of Generation, operates the Clinton Nuclear Power Station (Clinton), the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek).

 

The Operating Services Contract (OSC) with PSEG Nuclear, under which Generation administered daily plant operations at Salem and Hope Creek nuclear generating stations, was terminated during the fourth quarter of 2007, effective December 31, 2007 upon mutual agreement by both parties. Under the OSC, which commenced on January 15, 2005, PSEG Nuclear remained as the license holder with exclusive legal authority to operate and maintain both stations and retained responsibility for management oversight and full authority with respect to the marketing of its share of the output from the stations.

 

In 2007 and 2006, electric supply (in GWhs) generated from the nuclear generating facilities was 74% and 73%, respectively, of Generation’s total electric supply, which also includes fossil and hydroelectric generation and electric supply purchased for resale. During 2007 and 2006, the nuclear generating facilities operated by Generation achieved a 94.5% and 93.9% capacity factor, respectively.

 

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

 

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each station. 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, 2007, indicate 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 Byron Unit 2, which is still considered to be in an acceptable performance band in accordance with NRC standards.

 

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, and Quad Cities Units 1 and 2. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing Generation’s application for renewal. In July 2005, Generation applied for license renewal for Oyster Creek on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. The application was challenged by various citizen groups and the New Jersey Department of Environmental Protection (NJDEP). The contentions raised by these groups were reviewed by NRC’s Atomic Safety Licensing Board (ASLB). With the exception of one contention brought by the citizens group, involving drywell corrosion, the issues raised by these groups and by the NJDEP were dismissed prior to a hearing by the ASLB. The contention involving drywell corrosion went to an evidentiary hearing before the ASLB. On December 18, 2007, the ASLB dismissed this sole remaining contention. On January 14, 2008, the citizens group appealed the rejection of its contention to the NRC Commissioners. If the NRC rejects the appeal, the citizens group can further appeal to the Federal courts. In that regard, the NJDEP appealed to the Third Circuit Court of Appeals one of its rejected contentions asserting that the NRC must consider terrorism risks as part of the re-licensing proceeding. This contention had previously been rejected by the ASLB and the NRC Commissioners. Further, in January 2008, Generation received a letter from the NJDEP concluding that Oyster Creek’s continued operation is consistent with New Jersey’s Coastal Management Program, and approving Oyster Creek’s coastal land use plans for the next 20 years. This consistency determination is a necessary element for license renewal. With the NJDEP consistency determination and the rejection of the sole remaining contention by the ASLB, Generation is currently awaiting the NRC staff’s approval of the license renewal for Oyster Creek. The NRC’s approval is expected in 2008.

 

On January 8, 2008, AmerGen submitted an application to the NRC to extend the operating license of TMI Unit 1 for an additional 20 years from the expiration of its current license to April 2034. The NRC is expected to spend up to 30 months to review the application before making a decision. As with Oyster Creek, Generation expects various legal challenges to the renewal application, but ultimately expects approval from the NRC.

 

Generation expects to apply for and obtain approval of license renewals for the remaining facilities. The operating license renewal process takes approximately four to five years from the commencement of the project 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. The NRC has already approved 20-year renewals of the operating licenses for Generation’s Peach Bottom, Dresden and Quad Cities generating stations. The licenses for Peach Bottom Unit 2, Peach Bottom Unit 3, Dresden Unit 2, Dresden Unit 3, Quad Cities Unit 1 and Quad Cities Unit 2 were renewed to 2033, 2034, 2029, 2031, 2032 and 2032, respectively. Depreciation provisions are based on the estimated useful lives of the

 

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stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations except those for which renewal has already been received.

 

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

 

Station

   Unit    In-Service
Date (e)
   Current License
Expiration

Braidwood (a)

   1    1988    2026
   2    1988    2027

Byron (a)

   1    1985    2024
   2    1987    2026

Clinton (c)

   1    1987    2026

Dresden (a, d)

   2    1970    2029
   3    1971    2031

LaSalle (a)

   1    1984    2022
   2    1984    2023

Limerick (b)

   1    1986    2024
   2    1990    2029

Oyster Creek (c)

   1    1969    2009

Peach Bottom (b, d)

   2    1974    2033
   3    1974    2034

Quad Cities (a, d)

   1    1973    2032
   2    1973    2032

Salem (b)

   1    1977    2016
   2    1981    2020

Three Mile Island (c)

   1    1974    2014

 

(a) Stations previously owned by ComEd.
(b) Stations previously owned by PECO.
(c) Stations owned by AmerGen.
(d) NRC license renewals have been received for these units.
(e) Denotes year in which nuclear unit began commercial operations.

 

Generation is a member of NuStart Energy Development, LLC (NuStart), a consortium of ten companies that was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process. As of December 31, 2007, Generation’s investment in NuStart was $1 million.

 

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. On September 29, 2006, Generation notified the NRC that Generation will begin the application process for a combined Construction and Operating License (COL) that would allow for the possible construction of a new nuclear plant in Texas. The filing of the letter with the NRC launched a process that preserves for Exelon and Generation the option to develop a new nuclear plant in Texas without immediately committing to the full project. In order to continue preserving and assessing this option, Exelon and Generation have approved expenditures on the project of up to $100 million, which includes fees and costs related to the COL, reservation payments and other costs for long-lead components of the project, and other site evaluation and development costs. Amounts spent on the project to date through December 31, 2007 have been expensed and total approximately $49 million. The development phase of the project is expected to extend into 2009, and any decision to fund beyond the $100 million commitment would be subject to extensive analysis.

 

Generation has not made a decision to build a new nuclear plant at this time; however, on November 12, 2007, Generation announced that, if a decision is made to build a new nuclear plant in

 

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Texas, Generation will use GE-Hitachi Nuclear Energy Americas’ (GE-Hitachi) new reactor technology, known as the Economic Simplified Boiling Water Reactor, which uses simplified design features and fewer components, thereby allowing for faster construction, lower operating costs and enhanced safety features. Also, on December 18, 2007, Generation announced that it had selected a site in Victoria County in southeast Texas for its COL, which, if obtained, would allow construction and operation of a dual unit nuclear plant should Generation decide to proceed with the construction of the project.

 

On December 7, 2007, Generation reached an agreement with the City of San Antonio acting by and through the City Public Service Board, a Texas municipal utility known as CPS Energy (CPS), under which CPS agreed to fund a portion of Generation’s exploratory costs associated with the possible new nuclear power plant in southeast Texas and related costs for long-lead components. In exchange for its funding commitment, CPS received an option to acquire up to a 40% ownership interest in the new plant and its energy output. If CPS exercises its option, it will be obligated to fund its proportionate share of all project costs and liabilities. The decision whether to build the new nuclear plant will continue to reside solely with Exelon and Generation.

 

Among the various conditions that must be resolved before any formal decision to build is made are a workable solution to spent nuclear fuel (SNF) disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using the new technology can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, production and other potential tax credits, and other key economic factors. Generation expects to submit the COL application to the NRC in 2008.

 

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, 2007, Generation had approximately 48,400 SNF assemblies (11,700 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 license renewal period, and through decommissioning, until the U.S. Department of Energy (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

   2009

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

   Life of plant storage capable in SNF pool

 

(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.

 

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Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is responsible for the development of a repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kilowatthour (kWh) of net nuclear generation for the cost of nuclear fuel long-term disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE has published a schedule for opening a SNF permanent disposal facility and its current estimate is 2017. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration and development of dry cask storage at other stations. In August 2004, Generation and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement under which the government will reimburse Generation for costs associated with storage of spent fuel at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation plans to submit annual reimbursement requests to the DOE for costs associated with the storage of spent nuclear fuel. In all cases, reimbursement requests will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. See Note 14 of the Combined Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

 

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now owned by Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2007, the unfunded SNF liability for the one-time fee with interest (which has been assumed by Generation) was $997 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2007, was 4.025%. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The outstanding one-time fee obligations for the Oyster Creek and TMI units remain with the former owners. The Clinton Unit has no outstanding obligation.

 

As a by-product of their operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated at each generating station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site and none is currently expected to be operational until after 2011. 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 has on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to disposal facilities in South Carolina and Utah. With a limited number of available LLRW disposal facilities, Generation continues to anticipate difficulties in shipping of LLRW off of its sites, including the possibility that one or all of the available disposal facilities may not be available for some of Generation’s sites in the future. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts.

 

Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The Price-Anderson Act was extended to December 31, 2025

 

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under the terms of the Energy Policy Act of 2005. As of December 31, 2007, the current liability limit was $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.46 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for each nuclear operator per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $15 million per reactor per incident per year. This assessment is subject to inflation adjustment and state premium taxes. In August 2008, it is anticipated the $100.6 million and the $15 million maximum assessments will be adjusted due to inflation. The Price-Anderson Act, as amended, requires an inflation adjustment be made at least once each 5 years. The last inflation adjustment occurred in August 2003. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

 

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. Under the terms of the various insurance agreements, Generation could be assessed up to $172 million for losses incurred at any plant insured by the insurance companies. Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at an insured nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation’s maximum share of any assessment is $46 million per year.

 

See “Nuclear Insurance” within Note 19 of the Combined Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage and further information on NEIL.

 

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 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. As more fully described below, ComEd collected amounts from customers through 2006 for facilities formerly owned by ComEd, and PECO is currently collecting amounts from customers for facilities formerly owned by PECO, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission those nuclear facilities. AmerGen also maintains decommissioning trust funds for each of its plants. The AmerGen units, specifically Clinton, Oyster Creek, and TMI, are not covered by any rate recovery process for customer funding of decommissioning costs. Decommissioning expenditures are expected to occur primarily after the plants are retired. Certain decommissioning costs are currently being incurred.

 

Through 2006, under an ICC order, ComEd was permitted to recover amounts from customers to decommission former ComEd nuclear plants. ComEd is not permitted to collect amounts for decommissioning subsequent to 2006. Nuclear decommissioning costs associated with the nuclear generating stations formerly or partly owned by PECO continue to be recovered currently through rates charged by PECO to customers. The annual amount recovered, which in 2007 was $33 million, and effective January 1, 2008 will be $29 million, is remitted to Generation as allowed by the PAPUC. It is anticipated that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years, subject to certain limitations, to reflect changes in cost estimates and decommissioning trust fund performance. The amount recovered is premised on studies

 

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that assume level contributions through the license expiration date for each unit. After completion of the decommissioning, excess amounts in the decommissioning trusts for the nuclear generating stations formerly owned by ComEd and PECO that were collected from customers must be returned to ComEd and PECO customers, respectively, if those amounts exceed established thresholds.

 

Generation believes that the decommissioning trust funds for the nuclear generating stations formerly owned by ComEd and PECO, the expected earnings thereon and, in the case of PECO, the amounts currently being collected from PECO’s customers will be sufficient to fully fund Generation’s decommissioning obligations for the nuclear generating stations formerly owned by ComEd and PECO in accordance with NRC regulations. Generation further believes the AmerGen nuclear decommissioning trust funds together with expected investment earnings thereon will be sufficient to fully fund AmerGen’s decommissioning obligations in accordance with NRC regulations.

 

Any shortfall of funds necessary for decommissioning is ultimately required to be funded by Generation. Generation has recourse to collect additional amounts from PECO customers, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. No such recourse exists to collect additional amounts from ComEd customers or from the previous owners of AmerGen.

 

See Critical Accounting Policies and Estimates within ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Generation and Note 13 of the Combined Notes to Consolidated Financial Statements for a further discussion of nuclear decommissioning.

 

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 of Peach Bottom Unit 1’s SNF has been moved off site. SNF at Zion Station is currently stored in on-site storage pools. Generation’s liability to decommission Dresden Unit 1, Peach Bottom Unit 1 and Zion Station was $795 million at December 31, 2007. As of December 31, 2007, nuclear decommissioning trust funds set aside to pay for these obligations were $1.2 billion.

 

Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement with Energy Solutions, 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) associated with Zion Station, including assets held in nuclear decommissioning trusts (approximately $870 million). In consideration for Generation’s transfer of those assets, ZionSolutions will assume decommissioning and other liabilities associated with Zion Station. 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 spent nuclear fuel currently held in spent fuel 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 spent nuclear fuel 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

 

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specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all low level waste 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. If the transaction is completed in 2008, Generation expects the required decommissioning work and the construction of the dry cask spent fuel storage facility would be completed by 2018.

 

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 accuracy of the parties’ representations and warranties, the performance of covenants, the receipt of approval from the NRC, and the receipt of a private letter ruling from the Internal Revenue Service (IRS). Generation does not expect that conditions to the closing of the transaction will be satisfied before the second half of 2008.

 

Fossil and Hydroelectric Facilities

 

Generation operates various fossil and hydroelectric facilities and maintains ownership interests in several other facilities such as LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2007 and 2006, electric supply (in GWhs) generated from owned fossil and hydroelectric generating facilities was 6% and 7%, respectively, of Generation’s total electric supply, which also includes nuclear generation and electric supply purchased for resale. 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 Muddy Run and Conowingo facilities have licenses that expire in August 2014. Generation is in the process of performing pre-application analyses and anticipates filing a Notice of Intent to renew the licenses in 2009 pursuant to FERC regulations. For those plants located within the control areas administered by the PJM Interconnection, LLC (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.

 

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, 2007:

 

Seller

   Location    Expiration    Capacity (MWs)

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

   Jenks, Oklahoma    2022    795

Elwood Energy, LLC

   Elwood, Illinois    2012    775

Lincoln Generating Facility, LLC

   Manhattan, Illinois    2011    664

Reliant Energy Aurora, LP

   Aurora, Illinois    2008    600

Wolf Hollow 1, LP

   Granbury, Texas    2023    350

Duke Energy Trading and Marketing, LLC

   Dixon, Illinois    2008    344

Dynegy Power Marketing, Inc.

   East Dundee, Illinois    2009    330

DTE Energy Trading, Inc.

   Crete, Illinois    2008    300

Others (b)

   Various    2011 to 2028    486
          

Total

         7,524
          

 

(a) Commencing June 1, 2010 and lasting for 20 years, Generation has agreed to sell its rights to 942 MWs of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a tolling agreement with Georgia Power, a subsidiary of Southern Company.
(b) Includes long-term capacity contracts with nine counterparties.

 

Federal Power Act

 

The Federal Power Act gives FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. 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.

 

Market Based Rate Matters

 

Generation, ComEd and PECO are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale sales of electricity. Currently, Generation, ComEd and PECO have authority to sell power at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation or any of its affiliates has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

 

In 2004, FERC implemented market power tests to determine whether sellers should be entitled to market-based rate authority. The effect was to require Generation, ComEd, and PECO to file with FERC a new analysis under the new tests. On July 5, 2005, FERC accepted the filing, thereby allowing Generation, ComEd and PECO to have continued authority to sell at market-based rates. In the same order, however, FERC started a proceeding, the purpose of which was to require Generation to demonstrate its compliance with FERC’s affiliate abuse and reciprocal dealing prong of the tests it had

 

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instituted in 2004. On April 3, 2006, FERC accepted the compliance filing, and terminated the proceeding.

 

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, which updated and modified the tests that FERC had implemented in 2004. On December 14, 2007, FERC issued an order clarifying some provisions in the Final Rule. On January 14, 2008, Generation, ComEd and PECO filed an analysis using FERC’s updated screening tests, as required by the Final Rule. The filing demonstrates that under those tests, one called the pivotal supplier test and the other the market share test, Generation, ComEd, and PECO are entitled to continue to sell at market-based rates. FERC is not expected to act on the filing until later in 2008. The Registrants do not expect that the Final Rule will have a material effect on their results of operations in the short-term. The longer-term impact will depend on the future application by FERC of the Final Rule.

 

For a number of years, regional transmission organizations (RTOs), such as PJM, have formed in a number of regions to provide transmission service across multiple transmission systems. 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 Transmission Services below for a further discussion.

 

To date, PJM, the Midwest Independent Transmission System Operator, Inc. (MISO), ISO-NE and Southwest Power Pool, have been approved as RTOs. Because of some states’ opposition to imposition of centralized energy and capacity markets, FERC is seeking to obtain some of the benefits of RTOs by means of making more effective rules governing open-access transmission in regions that do not have RTOs or independent system operators.

 

The Energy Policy Act of 2005. The Energy Policy Act of 2005 (Energy Policy Act), which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in the transmission infrastructure, streamline electric regulation, improve wholesale competition, address problems identified in the western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

 

The Energy Policy Act, through amendment of the Federal Power Act, also transferred to FERC certain additional authority. FERC was granted new authority to review the acquisition or merger of companies owning generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. FERC was also authorized to impose civil penalties for violations of laws and regulations and to prohibit market manipulation activities. Additionally, FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also authorized a self-regulating electric reliability organization with FERC oversight to enforce reliability rules. On July 20, 2006, pursuant to the Federal Power Act, FERC certified the North American Electric Reliability Corporation (NERC) as the nation’s Electric Reliability Organization. As a result, users, owners and operators of the bulk power system, including Generation, ComEd and PECO, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC.

 

PJM Reliability Pricing Model (RPM)

 

FERC issued an order approving PJM’s RPM to replace its current capacity market rules. The RPM provides for a forward capacity auction using a demand curve and locational deliverability zones

 

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for capacity phased in over a several year period beginning on June 1, 2007. A number of parties have appealed the order, and those appeals have been consolidated and are pending in the United States Court of Appeals for the D.C. Circuit. Notwithstanding the petitions for judicial review, PJM implemented RPM in 2007 as FERC’s orders were not stayed, and therefore remain in effect, pending appellate review, as applicable. PJM’s RPM auctions took place in April 2007, July 2007, October 2007 and January 2008 and established prices for the period from June 1, 2007 through May 31, 2011. Subsequent auctions will take place 36 months ahead of the scheduled delivery year. The RPM is anticipated to have a favorable impact for owners of generation facilities, particularly for such facilities located in constrained zones. PJM is authorized to impose PJM RPM capacity penalties. As of December 31, 2007, Generation does not believe it has incurred any such penalties and, therefore, has not recorded a liability.

 

Marginal-Loss Dispatch and Settlement

 

On June 1, 2007, PJM implemented marginal-loss dispatch and settlement for its competitive wholesale electric market. Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy. Prior to the implementation of marginal-loss dispatch, PJM had used average losses in dispatch and in the calculation of locational marginal prices. Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads. PJM believes that the marginal-loss approach is more efficient because the cost of energy that is lost in transmission lines is reduced compared with the former average loss method. As a whole, Exelon and Generation have experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones due to the implementation of marginal-loss dispatch and settlement.

 

Illinois Settlement Agreement

 

The legislatively mandated transition and retail electric rate freeze period in Illinois ended at the close of 2006. In view of the rate increases following the expiration of the rate freeze, various bills were proposed in the Illinois House of Representatives and Senate in 2007 in an attempt to address the higher electric bills in the State of Illinois. In addition to proposed legislation directed at ComEd, the significant components of the proposed legislation directed at Generation would have required the following:

 

   

A tax of $70,000 for each megawatt of nameplate capacity on certain electric generating facilities located in Illinois including those owned by Generation.

 

   

Establishment of a generation tax and a fund from the proceeds of the generation tax to be used to pay to ComEd and other Illinois utilities for rate refunds to customers and also to pay to ComEd and other Illinois utilities for differences between 2007 and 2006 rates prior to July 1, 2008.

 

   

Require electric utilities, including ComEd, to remove themselves from participation in RTOs, including PJM, which would have had a significant impact on competition and open-access in the Illinois retail market.

 

In July 2007, following extensive discussions with legislative leaders in Illinois, Generation, ComEd, and other generators and utilities in Illinois reached an agreement (Settlement) with various representatives from the State of Illinois 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 have been harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Generation and ComEd committed to contributing approximately $800 million to rate relief programs over four years. Generation committed an aggregate of $747 million, with $435 million available to pay ComEd for rate relief programs for ComEd customers, $307.5 million available

 

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for rate relief programs for customers of other Illinois utilities, and $4.5 million available for partially funding operations of the IPA. Legislation reflecting the Settlement (Settlement Legislation) was passed by the Illinois Legislature on July 26, 2007 and was signed into law on August 28, 2007 by the Governor of Illinois. See Note 4 of the Combined Notes to Consolidated Financial Statements for the components of the Settlement Legislation.

 

Fuel

 

The following table shows sources of electric supply in GWhs for 2007 and estimated for 2008:

 

     Source of Electric Supply (a)
         2007          2008   (Est.)

Nuclear units

   140,359    138,056

Purchases—non-trading portfolio

   38,021    36,741

Fossil and hydroelectric units

   11,270    14,487
         

Total supply

   189,650    189,284
         

 

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

 

The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its obligations for sales to other utilities, 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 2010. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2011. All of Generation’s enrichment requirements have been contracted through 2011. Contracts for fuel fabrication have been obtained through 2010. 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.

 

Generation obtains approximately 30% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. against European enrichment services suppliers alleging dumping in the United States. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals; however, as a result of these actions, Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

 

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

 

Natural gas is procured for gas-fired plants 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.

 

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Generation uses financial instruments to mitigate price risk associated with commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information regarding derivative financial instruments.

 

Power Team

 

Generation’s wholesale 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 with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers. Power Team may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be made 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. 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.

 

Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. The maximum length of time over which cash flows related to energy commodities are currently being economically hedged is approximately five years. Generation has estimated a greater than 90% economic and cash flow hedge ratio for 2008 for its energy marketing portfolio. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to ComEd and PECO. A portion of Generation’s hedge may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, energy market option volatility and actual loads. 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 Risk Management Committee (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, 2007, Generation’s long-term commitments relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:

 

(in millions)

   Net Capacity
Purchases (a)
   Power Only Purchases
from Non-Affiliates
   Power Only
Sales
   Transmission Rights
Purchases (b)

2008

   $ 335    $ 473    $ 3,371    $ 2

2009

     291      38      1,486      —  

2010

     316      18      277      —  

2011

     324      48      27      —  

2012

     321      18      28      —  

Thereafter

     1,848      207      29      —  
                           

Total

   $ 3,435    $ 802    $ 5,218    $ 2
                           

 

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(a) Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2007. Expected payments include certain capacity charges which are conditional on plant availability.
(b) Transmission rights purchases include estimated commitments in 2008 for additional transmission rights that will be required to fulfill firm sales contracts.

 

Beginning in January 2007, ComEd began procuring all of its energy requirements for retail customers from market sources pursuant to the ICC-approved procurement auction in 2006 or from the PJM spot market. Approximately one-third of ComEd’s contracts that resulted from the 2006 auction will expire in May 2008, another one-third will expire in May 2009, and the remaining contracts will expire in May 2010. Approximately 35% of the contracted supply from the 2006 auction will come from Generation. Suppliers, including Generation, were limited to winning no more than 35% in either the fixed price section or the hourly price section of the auction. The Settlement Legislation established a new competitive process for procurement to be managed by the IPA and overseen by the ICC in accordance with electricity supply procurement plans approved by the IPA. The new procurement process involving the IPA will not be fully established until later in 2008 and, in the interim, ComEd submitted to the ICC, and the ICC approved, a procurement plan for ComEd to secure its remaining requirements for power and other ancillary services for the period from June 2008 to May 2009. Beginning in 2008, ComEd, each June, will submit a five-year forecast to the IPA and the IPA will develop a procurement plan for approval by the ICC to procure its remaining requirements for energy in periods subsequent to May 2009.

 

Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially 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 expects to procure all of its electricity from market sources, which could include Generation.

 

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 2008 are as follows:

 

(in millions)

    

Production plant

   $ 868

Nuclear fuel (a)

     731
      

Total

   $ 1,599
      

 

(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 subject to regulation by the ICC as to rates and service, the issuance of securities, and certain other aspects of ComEd’s operations. ComEd is also subject to regulation by FERC as to transmission rates and certain other aspects of ComEd’s business.

 

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

 

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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 2008 to 2061. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

 

ComEd’s kWh sales and load of electricity are generally higher during the summer periods and winter periods, 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 MWs; its highest peak load during a winter season occurred on February 5, 2007 and was 16,207 MWs.

 

Retail Electric Services

 

Electric utility restructuring legislation was adopted in Illinois in December 1997 to permit competition by competitive electric generation suppliers for the supply of retail electricity. Transmission and distribution service was not impacted by the legislation and continues to remain regulated. The restructuring legislation and related regulatory orders allowed customers to choose a competitive electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allowed the collection of competitive transition charges (CTCs) from customers to permit Illinois utilities to recover a portion of the costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period. ComEd’s transition and rate freeze period ended in January 2007.

 

In anticipation of the end of the transition and rate freeze period, ComEd engaged in various regulatory proceedings to establish rates for the post-2006 period, as described below. In view of the rate increases that were anticipated following the expiration of the rate freeze, the Illinois Legislature considered proposed legislation to roll back and freeze ComEd’s rates for an additional period, to control the rate at which the rate increases were phased in or to impose a tax on the ownership or operation of electric generating facilities. In August 2007, Settlement Legislation was enacted in Illinois to address concerns about higher electric bills following the expiration of the rate freeze. The Settlement Legislation required, among other things, rate relief contributions of approximately $1 billion to be made by certain Illinois electric utilities, their affiliates, and generators of electricity in Illinois over a four-year period. ComEd committed to continue executing upon a $64 million rate relief package announced earlier in 2007.

 

As a result of the end of ComEd’s transition period, new unbundled rates for service became effective in January 2007. As of December 31, 2007, three competitive electric generation suppliers have been granted approval by the ICC to serve residential customers in Illinois; however, none of the competitive electric generation suppliers is currently supplying electricity to any of ComEd’s residential customers. All of ComEd’s customers are eligible to choose a competitive electric generation supplier or may purchase electricity from ComEd at market-based rates. At December 31, 2007, approximately 44,200 non-residential customers, representing approximately 48% 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 full service electric service including generation service (which are referred to as provider of last resort (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 kilowatts (kWs) 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.

 

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ComEd’s obligations to many of its largest customers, with demands of 3 MWs or greater has previously been declared competitive. For customers with demands of 400 kWs and above, and 100-400 kWs, ComEd has full service obligations through May 2008 and May 2010, respectively.

 

Delivery Service Rate Cases. In August 2005, ComEd filed a rate case with the ICC to comprehensively review its tariff and to adjust ComEd’s rates for delivering electricity effective January 2007 (2005 Rate Case). In July 2006, the ICC issued its order in the 2005 Rate Case, approving a delivery services revenue increase of approximately $8 million of the $317 million proposed revenue increase requested by ComEd. The ICC subsequently granted, in part, requests for rehearing of ComEd and various other parties, and in December 2006, issued an order on rehearing that increased the amount previously approved by approximately $74 million for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts, but the appeal is not yet resolved.

 

In October 2007, ComEd filed a request with the ICC seeking approval to increase its delivery service rates to reflect its continued investment in delivery service assets since rates were last determined (2007 Rate Case). ICC proceedings relating to the proposed delivery service rates will occur over a period of up to eleven months. If approved by the ICC, the total proposed increase of approximately $360 million in the net annual revenue requirement, which was based on a 2006 test year with estimated capital additions through the third quarter of 2008, would increase an average residential customer’s total bill by approximately 7.7%.

 

Illinois Rate Design. In October 2007, the ICC-approved implementation of a revised rate design that changed the allocation of rates among customer groups effective December 1, 2007, but did not change the overall level of rates. The new rate design took effect December 1, 2007.

 

Procurement Related Proceedings. Beginning January 1, 2007, following the expiration of a PPA with Generation, ComEd began procuring electricity under supplier forward contracts with various suppliers, including Generation. The supplier forward contracts resulted from an ICC-approved “reverse-auction” competitive bidding process, which permitted recovery by ComEd of its electricity procurement costs from retail customers with no markup. A procurement auction for ComEd’s entire load occurred in September 2006 and deliveries resulting from the auction began in January 2007. The energy price that resulted from the procurement auction is fixed until June 2008, at which time, approximately one-third of supply contracts entered as part of the procurement auction are scheduled to expire. The Settlement Legislation established a new competitive process which must be used by Illinois utilities for the procurement of electricity and also established the IPA. With the exception of the delivery period beginning in June 2008, the IPA will participate in the design of electricity supply portfolios for ComEd and will administer the new competitive process for ComEd to procure the electricity supply resources and renewable energy sources identified in its supply portfolio plans, all under the oversight of the ICC. In October 2007, ComEd filed a petition with the ICC seeking approval of an initial procurement plan to secure energy for retail electric customers for the period June 2008 through May 2009. On December 11, 2007, an administrative law judge (ALJ) issued a proposed order on the procurement plan, approving virtually every aspect of the proposal, with the exception of recommending an increase in the amount of power ComEd should procure through block purchases in July and August for peak periods (Proposed Order). On December 19, 2007, the ICC approved the Proposed Order. The procurement plan and the spot market purchases discussed below will be used to effectively replace the auction contracts scheduled to expire on May 31, 2008 to meet the power and other ancillary services requirements of ComEd’s customers for the period June 2008 through May 2009. In May 2009, another one-third of existing auction contracts will expire and any additional electricity required to meet the needs of ComEd’s customers will be acquired through the new competitive process administered by the IPA.

 

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Under the Settlement Legislation, electric utilities are required to use cost-effective energy efficiency resources to meet incremental annual program energy savings goals and must implement cost-effective demand response measures to reduce peak demand each year for eligible retail customers. In November 2007, pursuant to these requirements, ComEd filed its initial Energy Efficiency and Demand Response Plan with the ICC and expects an ICC order to be issued on the filing in the first quarter of 2008. This plan begins in June 2008, and is designed to meet the Settlement Legislation’s energy efficiency and demand response goals for an initial three-year period, including reductions in delivered energy and in the peak demand of ComEd’s customers.

 

In addition to the procurement plan, ComEd will purchase energy on the spot market to meet the needs of its customers. To fulfill another requirement of the settlement that gave rise to the Settlement Legislation, and in advance of the creation of the IPA, ComEd and Generation entered into a five-year financial swap contract that became effective in August 2007. This contract effectively hedges a significant portion of ComEd’s spot market purchases. The effect of the swap is to cause ComEd to pay fixed prices and Generation to pay market prices for a portion of ComEd’s electricity supply requirements. The financial swap contract is designed to dovetail with ComEd’s remaining supplier forward contracts for energy, increasing in volume as those contracts expire. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Other. Illinois law provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous electricity outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. Recovery of consequential damages is barred and the affected utility may seek relief from these provisions from the ICC when the utility can show that the cause of the outage was unpreventable due to weather events or conditions, customer tampering or third-party causes. During the years 2007, 2006 and 2005, ComEd does not believe that it had any outages that triggered the reimbursement requirement.

 

Construction Budget

 

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2008 are $1,003 million.

 

PECO

 

PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to residential, commercial and industrial 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 residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is 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 also subject to regulation by FERC as to transmission rates and certain other aspects of PECO’s business.

 

PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied 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 480,000 customers.

 

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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 periods and winter periods, 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 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.

 

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

 

Retail Electric Services

 

Electric utility restructuring legislation was adopted in Pennsylvania in December 1996. Pennsylvania permits competition by competitive electric generation suppliers for the supply of retail electricity while transmission and distribution service remains regulated. The legislation and related regulatory orders allowed customers to choose a competitive electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allowed the collection of CTCs from customers to recover a portion of the costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period. The PECO transition period ends on December 31, 2010.

 

Under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), all of PECO’s retail electric customers have the right to choose their generation suppliers. At December 31, 2007, less than 1% of each of PECO’s residential and large commercial and industrial loads and 8% of its small commercial and industrial load were purchasing generation service from competitive electric generation suppliers. Customers who purchase electricity from a competitive electric generation supplier continue to pay a delivery charge and CTC to PECO. In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case (1998 restructuring settlement) mandated by the Competition Act established caps on generation, transmission and distribution rates. The 1998 restructuring settlement also authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery, which was subsequently increased to $5.0 billion.

 

Under the 1998 restructuring settlement, PECO’s electric distribution and transmission rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, are capped through December 31, 2010. In 2007, the generation rate cap increased to $0.0801 per kWh, where it will remain through 2010. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Under the settlement agreement entered into by PECO in 2000 relating to the PAPUC’s approval of the merger between PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO/Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution and transmission rates through December 31, 2006. PECO’s transmission and distribution rates continue in effect until PECO

 

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files a rate case or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so.

 

As a mechanism for utilities to recover allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable CTCs on customers’ bills. CTCs are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utility’s transmission and distribution systems. As the transition charges are based on access to the utility’s transmission and distribution system, they are assessed regardless of whether the customer purchases electricity from the utility or a competitive electric generation supplier. The Competition Act provides, however, that the utility’s right to collect CTCs is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

 

As mentioned above, PECO has been authorized by the PAPUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. At December 31, 2007, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was approximately $2.4 billion. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2008 through 2010 as authorized by the PAPUC based on the level of transition charges established in the settlement of PECO’s restructuring case and the projected annual retail sales in PECO’s service territory. Recovery of CTCs for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. To the extent the actual recoveries of CTCs in any one year differ from the authorized amount set forth below, an annual reconciliation adjustment to the CTC rates is made to increase or decrease the subsequent year’s collections accordingly, except during 2010, in which the reconciling adjustments are made quarterly or monthly as needed.

 

Year (in millions)

   Estimated
CTC Revenue
   Estimated Stranded
Cost Amortization

2008

   $ 917    $ 697

2009

     924      783

2010

     932      883

 

PECO has a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

 

Default Service Regulations. Under Pennsylvania law, PECO is required to provide generation services to 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. These requirements are referred to as default service regulations. In May 2007, the PAPUC adopted final default service regulations, an accompanying policy statement, and a price mitigation policy statement. The final default service regulations became effective on September 15, 2007. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Pennsylvania Regulatory Matters. In 2007, the Pennsylvania Governor announced an Energy Independence Strategy that addresses the impact of electricity price increases in Pennsylvania and other initiatives on the Pennsylvania Governor’s environmental agenda. The Energy Independence Strategy includes measures that would, among other things, phase-in increased electricity rates following the expiration of rate caps, require the installation and use of advanced metering technology and establish an Energy Independence Fund to spur the development of a biofuels industry in

 

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Pennsylvania and promote the advancement of energy efficiency and renewable energy initiatives. As of February 7, 2008, no portion of the Governor’s environmental agenda has been enacted into law. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

 

Alternative Energy Portfolio Standards Act. In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that beginning in 2007, or at the end of an electric distribution company’s transition period during which CTCs are being recovered, certain percentages of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from certain alternative energy resources. On December 20, 2007, the PAPUC approved PECO’s plan to acquire up to 240 MWs of alternative energy credits per year for a five-year term. See “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” for additional information.

 

Natural Gas

 

PECO’s natural gas sales and transportation revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a portion of total rates, are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates. PECO’s natural gas distribution base rates for recovery of costs other than purchased natural gas costs will continue in effect until PECO files a rate case or there is some other specific regulatory action to adjust the rates.

 

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 30% of PECO’s current total yearly throughput is provided by 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.

 

PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to two years. These purchases are delivered under long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 43 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 34% of PECO’s 2007-2008 heating season planned supplies.

 

Construction Budget

 

PECO’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2008 is $394 million.

 

ComEd and PECO

 

Transmission Services

 

ComEd and PECO provide unbundled retail 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

 

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facilities under filed tariffs at cost-based rates. Under FERC’s Order Nos. 889 and 2004, 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 or the employees of any energy affiliate of the transmission owner.

 

PJM is the independent system operator 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.

 

In March 2007, ComEd filed a request with FERC seeking approval to update its transmission rates and change the manner in which ComEd’s transmission rates are determined from fixed rates to a formula rate. Those matters were resolved in a settlement agreement that was certified by a Settlement Judge in October 2007 and approved by FERC on January 18, 2008. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

In November 2004, FERC issued two orders authorizing ComEd and PECO to recover amounts for a limited time during a specified transitional period as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of or across their respective transmission systems and ending within pre-expansion territories of PJM or MISO. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), were collected from load-serving entities and paid to transmission owners within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. A hearing was held in May 2006 and the ALJ issued an initial decision in August 2006 finding that the transmission owners overstated their lost revenues in their compliance filings and the SECA rate design was flawed. Additionally, the ALJ recommended that the transmission owners should be ordered to refile their respective compliance filings related to SECA rates. ComEd and PECO filed exceptions to the initial decision and FERC, on review, will determine whether or not to accept the ALJ’s recommendation. There is no scheduled date for FERC to act on this matter. Separately, settlements have been reached by ComEd and PECO with various parties and by other transmission owners. FERC has approved several of these settlements while others are still awaiting FERC approval. Management of both ComEd and PECO believes that appropriate reserves have been established for the estimated portion of SECA collections that may be required to be refunded. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

On May 31, 2005, FERC issued an order creating an evidentiary hearing process to examine the existing PJM transmission rate design. A number of parties proposed the replacement of that rate design, in which customers in a zone pay a transmission rate based on the cost of transmission facilities in that zone, with several variations including a postage stamp rate design across PJM in which a single, uniform charge would be applied based on the costs of all transmission facilities within PJM wherever located. On July 13, 2006, the ALJ in the case issued an Initial Decision that recommended that FERC implement the postage stamp rate, effective as of April 1, 2006, but also allowed for the potential to phase in rate changes. On April 19, 2007, FERC issued its order on review of the ALJ’s decision. FERC held that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. That is consistent with Exelon’s position in the case. FERC also held that the costs of new facilities should be allocated under a different rate design. FERC held

 

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that the costs of new 500 kilovolts (kV) and above facilities should be socialized across the entire PJM footprint and that the costs of new less than 500 kV facilities should be allocated to the beneficiaries of the new facilities. FERC stated that PJM’s stakeholders should develop a standard method for allocating the costs of new transmission facilities lower than 500 kV. FERC’s decision on existing facilities does not change existing costs, which is substantially more favorable to Exelon than the ALJ’s decision on existing facilities. In the short term, based on new transmission facilities approved by PJM, it is likely that allocating the costs of new 500 kV facilities across PJM will increase costs to ComEd and reduce costs to PECO, as compared to the allocation methodology in effect before the FERC order. ComEd and PECO cannot estimate the longer-term impact on either company’s results of operations and cash flows, because of the uncertainties relating to what new facilities will be built and how the costs of new facilities less than 500 kV will be allocated. On May 21, 2007, Exelon and other parties filed requests for rehearing of FERC’s April 19, 2007 order. Exelon, on behalf of ComEd, PECO, and Generation, filed for rehearing solely on the issue of socialization of the costs of new facilities 500kV and above. On January 31, 2008, FERC denied rehearing on all issues. FERC’s decision may be subject to review in the United States Court of Appeals.

 

On August 1, 2007, ComEd, PECO and several other transmission owners in PJM and the MISO, as directed by a FERC order issued November 18, 2004, filed with FERC to continue the existing transmission rate design between PJM and MISO. On August 22, 2007, additional transmission owners and certain other entities filed protests urging FERC to reject the filing. On January 31, 2008, FERC accepted the filing. FERC’s decision may be subject to requests for rehearing and to review in the United States Court of Appeals. On September 17, 2007, a complaint was filed at FERC asking FERC to find that the PJM-MISO rate design was unjust and unreasonable and to substitute a rate design that socializes the costs of all existing and new transmission facilities across PJM and MISO. ComEd and PECO filed a response in October 2007 stating that FERC should dismiss the complaint without a hearing. On January 31, 2008, FERC denied the complaint. FERC’s decision may be subject to requests for rehearing and to review in the United States Court of Appeals. This matter remains pending.

 

Employees

 

As of December 31, 2007, Exelon and its subsidiaries had approximately 17,800 employees in the following companies:

 

Generation

   8,000

ComEd

   5,900

PECO

   2,300

Other (a)

   1,600
    

Total

   17,800
    

 

(a) Other includes shared services employees at Exelon Business Services Company, LLC (BSC).

 

Approximately 5,500 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 750 employees. The Generation CBA with IBEW Local 15 has been extended to September 30, 2010. The CBA for ComEd and BSC expires on September 30, 2008. In addition, a separate CBA between ComEd and IBEW Local 15, which was ratified on November 7, 2006, covers approximately 160 employees in ComEd’s System Services Group and expires on October 1, 2009. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2010, January 31, 2010 and February 28, 2009,

 

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respectively. Approximately 1,270 PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614. The CBAs cover work hours, wages, benefits and working conditions for the represented employees. The CBAs will expire on March 31, 2010. In addition, Exelon Power, an operating unit of Generation, has an agreement with Utility Workers of America Local 369, covering approximately 15 employees, which was ratified effective January 31, 2007 and expires January 31, 2011. Exelon Power has an agreement with IBEW Local 614, which expires on February 1, 2011 and covers approximately 250 employees.

 

The employees of the Limerick and Peach Bottom nuclear stations are not represented by a union. On May 5, 2005, a majority of these employees elected not to be represented by the IBEW 614. After contesting the election, the National Labor Relations Board ruled that a new election must be conducted. This election took place on November 16, 2006. The employees again voted against union representation.

 

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 United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies. Various state environmental protection agencies or boards have jurisdiction over certain activities in states in which Exelon and its subsidiaries do business. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals.

 

Water

 

Under the Federal Clean Water Act, National Pollutant Discharge Elimination System (NPDES) permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated. Those permits must be renewed periodically. Generation either has NPDES permits for all of its generating stations or has pending applications for renewals of such permits while operating under an administrative extension.

 

In July 2004, the 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 entrainment and impingement of aquatic organisms at existing power plants. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in a challenge to the final Phase II rule brought by environmental groups and several states. The court found that with respect to a number of significant provisions of the Phase II rule, the EPA either exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the matter back to the EPA for revisions of the Phase II rule consistent with the court’s opinion. The court’s opinion has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. Several industry parties to the litigation sought review by the entire U.S. Court of Appeals for the Second Circuit, which was denied on July 5, 2007. On November 2, 2007, the industry parties filed petitions seeking review by the U.S. Supreme Court. The respondent environmental and state parties have until February 29, 2008 to respond to the petitions. On July 9, 2007, the EPA formally suspended the Phase II rule due to this uncertainty. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies have been instructed by the EPA to continue the current practice of applying their best professional judgment to

 

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address impingement and entrainment requirements at plant cooling water intake structures. See Note 19 of the Combined Notes to Consolidated Financial Statements for detail on the impact of this rule to Generation.

 

On December 16, 2005 and February 27, 2006, the Illinois EPA issued notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. On March 16, 2006, the Attorney General of the State of Illinois, and the State’s Attorney for Will County, Illinois filed a civil enforcement action, seeking, among other things, injunctive relief to require certain remedial actions for past tritium releases, and to prevent future releases. In addition, there is one remaining lawsuit alleging property contamination and seeking damages for diminished property value that was filed by a resident owning property near the plant. The allegations in the complaint are substantially similar to prior lawsuits filed by area residents that were voluntarily dismissed by the plaintiffs without prejudice. On December 27, 2007, the judge dismissed Exelon from this litigation, and on January 28, 2008, the judge granted Generation’s motion for summary judgment against the plaintiffs. The plaintiffs have 30 days from the order of summary judgment to appeal to the U.S. Circuit Court for the Seventh Circuit. Generation believes that appropriate reserves have been recorded for State of Illinois fines and remediation costs in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5) as of December 31, 2007 and 2006.

 

Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood, as discussed above. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors. See Note 19 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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

 

Solid and Hazardous Waste

 

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), provides for immediate response and removal actions coordinated by the 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 EPA on the National Priorities List (NPL). These potentially responsible parties (PRPs) can be ordered to perform a cleanup, can be sued for costs associated with an 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 enacted statutes that contain provisions substantially similar to CERCLA. In addition, the Resource Conservation and Recovery Act (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 EPA, state agencies and/or other responsible parties under CERCLA and

 

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RCRA with respect to a number of sites, including manufactured gas plant (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.

 

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. ComEd and PECO have identified former MGP sites for which they may be liable for remediation. ComEd and PECO perform a detailed study of the MGP reserve on a periodic basis. ComEd and PECO believe that appropriate reserves have been recorded. See Note 19 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Cotter Corporation

 

The 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. Generation 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 19 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Air

 

Air quality regulations promulgated by the EPA and the various state 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. The Amendments include a two-phase program to reduce acid rain effects by significantly reducing emissions of SO2 and NOx from power plants. Flue-gas desulphurization systems (SO2 scrubbers) have been installed at all of Generation’s coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Acid Rain Program Phase II SO2 and NOx limits of the Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners formally approved on June 30, 2006 a capital plan to install SO2 scrubbers at the station for which Exelon’s share, based on its 20.99% ownership interest, would be approximately $150 million. As of December 31, 2007 and December 31, 2006, total costs incurred, including capitalized interest, were $27 million and $4 million, respectively. Exelon anticipates spending approximately $93 million and $26 million in 2008 and 2009, respectively, related to this project. The Keystone SO2 scrubbers are expected to be operational by 2009. In addition, Generation and the other Keystone co-owners purchase SO2 emission allowances as part of their compliance strategy to meet Phase II limits.

 

During March 2005, the EPA finalized several new rulemakings designed to reduce power plant emissions of SO2, NOx and mercury. In its Clean Air Interstate Rule (CAIR), the EPA established new annual (applicable in 23 eastern states) and ozone season (applicable in 25 eastern states) NOx emission caps that are scheduled to take effect in 2009. Further, CAIR requires an additional reduction of SO2 emissions in 23 eastern states starting in 2010. CAIR also requires an additional reduction of NOx and SO2 emissions in 2015. The new SO2 and NOx emission caps finalized by the EPA are substantially below current industry emission levels. Starting in 2009, the CAIR regulations will replace

 

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the current EPA “NOx State Implementation Plan (SIP) Call” regulation that currently regulates summertime NOx emissions, under a cap and trade program, from most of Exelon’s fossil generation in the affected eastern United States (except Texas). Exelon is currently operating in compliance with the NOx SIP Call and has installed various NOx pollution control devices at a number of its fossil units to reduce NOx emissions. Exelon’s fossil units in the Dallas/Fort Worth area currently operate under tight state and local NOx regulations and will be further regulated by the annual NOx requirements of CAIR starting in 2009. In addition, Exelon’s fossil units in the Dallas/Fort Worth area will be subject to more stringent state NOx regulations starting in 2009.

 

In a separate rulemaking, also issued in March 2005, the Clean Air Mercury Rule (CAMR), the EPA finalized a national program to cap mercury emissions from coal-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. In its final CAMR, the EPA determined that it would not regulate nickel emissions from oil-fired power plants, as it had considered in its proposed rulemaking. Generation is currently evaluating its compliance options with regard to the final CAIR and CAMR regulations. Final compliance decisions will be affected by a number of factors, including, but not limited to, the final form of state implementing regulations, some of which are still under development, as well as the resolution of legal challenges to the Federal rules initiated by certain parties (not including Exelon) in the Federal courts.

 

During 2006, Pennsylvania enacted a state-level mercury regulation that is more stringent than the Federal CAMR. Under the first phase of the regulation, starting in 2010, pulverized coal units will be required to meet either an emission rate of 0.024 lb mercury/GWh or an 80% mercury capture efficiency and comply with a unit-level annual mercury emissions limit that must be met by surrendering non-tradable mercury allowances. Under the second phase of the final regulation, starting in 2015, units will be required to meet either a 0.012 lb/GWh emission rate or 90% capture efficiency and a reduced annual emissions limit. While the PDEP rulemaking does not allow for mercury emission allowance trading for compliance, it does allow for emission limit compliance on a facility or system-wide (under common ownership) basis. Exelon is currently developing its compliance plans for Pennsylvania and expects a significant portion of its compliance will be achieved via co-benefit mercury reductions resulting from existing SO2 scrubber operations at Eddystone and Cromby coal units, as well as the planned SO2 scrubbers at the Keystone 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 introduced that would reduce generating plant emissions of NOx, SO2, mercury and carbon dioxide starting late this decade and into the next decade.

 

At this time, Exelon can provide no assurance that new legislative and regulatory proposals, if adopted, will not have a significant effect on Generation’s operations and cash flows.

 

On August 6, 2007, ComEd received a Notice and Finding of Violation (NOV), addressed to it and Midwest Generation, LLC (Midwest Generation) from the EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Federal Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The EPA requested information related to the stations in 2003, and ComEd has been cooperating with the EPA since the time of such request. The NOV states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the Clean Air Act.

 

The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of

 

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the agreement governing that sale, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME further agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

 

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations related to its former generation business. At this time, Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV, the costs that might be incurred by Generation or the amount of indemnity that may be available from Midwest Generation and EME; however Exelon, Generation and ComEd concluded that a loss is not probable and, accordingly, they have not recorded a reserve for the NOV.

 

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 greenhouse gases (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, hydroelectric and landfill gas), has a relatively small GHG emission profile or carbon footprint compared to other 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 kWh of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions from the direct combustion of fossil fuels 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 combustion of fossil fuels represent approximately 90% of Exelon’s total GHG emissions; this is also the most variable component of its emissions to forecast due to the intermediate and peaking profile of Exelon’s fossil generating fleet. However, only approximately 7% of Exelon’s total electric supply is provided by the fossil fuel generating plants owned by Exelon. Other GHG emission sources at Exelon include natural gas (methane) leakage on its gas pipeline system, sulfur hexafluoride (SF6) leakage in its electric operations and refrigerant leakage from its chilling and cooling equipment as well as fossil combustion in its motor vehicles. Despite this small carbon footprint, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and through mandatory programs to reduce GHG emissions.

 

Physical Risks. 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 Exelon’s operations. Exelon is currently evaluating potential physical risk issues to its operations resulting from climate change, as well as potential options to manage those risks.

 

In general, weather patterns and the related impact on electricity and gas usage affect Exelon’s results of operations. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures in the winter adversely affect the usage of energy and resulting revenues. Extreme weather conditions may stress ComEd’s and PECO’s transmission and distribution systems, resulting in increased maintenance and capital expenditures and challenging their ability to meet peak customer demand, thereby causing detrimental effects on ComEd’s and PECO’s operations.

 

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Generation’s operations are also affected by weather, both in terms of demand for electricity and in operating conditions. The effects of unusually warm or cold weather on Generation’s results of operations depend on the nature of its market position at the time of the unusual weather. Generation plans its business based upon normal weather assumptions while performing analysis and necessary planning for severe weather driven scenarios. 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 requirements. Extreme weather conditions or storms may affect the availability of generation and transmission capacity, limiting Generation’s ability to source or send power to where it is needed. These conditions, which cannot be reliably predicted, may have an adverse effect by requiring 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.

 

Additionally, Exelon is affected by the occurrence of extreme weather events such as hurricanes and storms in its service territories and throughout the United States. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within Exelon’s service areas can also directly affect Exelon’s 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 continued operation, particularly the cooling of Exelon’s generating units.

 

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

 

Numerous bills have been introduced in Congress that address climate change from different perspectives, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap and trade), a tax on carbon emissions and incentives to develop low-carbon technology. Exelon supports the enactment, through Federal legislation, of a cap-and-trade system for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and the competitiveness of U.S business. Exelon’s fossil generation already operates under cap and trade programs for NOx and SO2. Exelon believes that any mechanism for allocation of emission credits should include allowances for distribution companies to help offset the cost of GHG emission credits for the end-user. In addition, Exelon supports a pre-determined cap on the price of emission allowances (cost containment mechanisms) that escalates over time, to limit economic effects of the cost of GHG regulation.

 

Two major bills have been introduced in the United States Senate, the Bingaman-Specter Low Carbon Economy Act and the Lieberman-Warner America’s Climate Security Act. Both bills create an economy-wide, cap-and-trade program. The Low Carbon Economy Act would reduce emissions by 15% below 2005 levels by 2030, set a safety-valve price for CO2 emissions at $12 per metric ton of CO2 emissions rising 5% above inflation per year, and initially auction 24% of allowances rising to 53% in 2030. Under the Low Carbon Economy Act, 29% of total allowances are given, at no charge, to generators in the electric sector based on heat input. The America’s Climate Security Act would reduce emissions by 70% from 2005 levels from covered sources by 2050, create a Carbon Market Efficiency Board to control costs of the program and initially auction 26.5% of the allowances rising to 69.5% in 2031. The bill gives 19% of the allowances to electric generators based on their heat input and 9% of allowances to electric local distribution companies for the benefit of their customers. The allowances to generators phase out to zero by 2031. On December 5, 2007, the Senate Environment and Public

 

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Works Committee approved America’s Climate Security Act by a vote of 10 to 8. The full Senate is expected to debate the legislation in 2008. The House of Representatives Energy and Commerce Committee has not introduced a vehicle for debate to address climate change.

 

Legislative efforts in Illinois and Pennsylvania related to climate change have focused primarily on energy efficiency, demand response and renewable energy initiatives. The Settlement Legislation enacted in Illinois in 2007 requires electric utilities to use cost-effective energy efficiency resources to meet specific incremental annual energy savings goals. The Settlement Legislation also requires procurement plans of electric utilities in Illinois to include cost-effective renewable energy resources that meet a defined portion of total electricity supplied to retail customers. In Pennsylvania, the Alternative Energy Portfolio Standards Act of 2004 mandated that, beginning in 2007 or at the end of an electric distribution company’s restructuring period, specified percentages of electric energy sold by the electric distribution company or the electric generation supplier to Pennsylvania retail electric customers must come from alternative energy resources.

 

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U. S. Environmental Protection Agency holding that CO2 and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions not only from motor vehicles but also from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule and Federal or state legislation.

 

At a regional level, on August 24, 2005, the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by Northeastern and Mid-Atlantic states to reduce CO2 emissions, released a program proposal. The RGGI Memorandum of Understanding (MOU) is an agreement to stabilize aggregate CO2 emissions from power plants in participating states at current levels from 2009 to 2015. Further, reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO2 emissions. As of December 31, 2007, states participating in the RGGI MOU include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont. On August 15, 2006, the RGGI model rule was finalized, and RGGI member states are currently in the process of adopting state-level rules to implement the program starting in 2009. Generation owns a small amount of affected peaking and intermediate generating capacity in the RGGI region, including Maine, Massachusetts and New Jersey. On November 15, 2007, six midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota, Wisconsin) signed the Midwestern Greenhouse Gas Accord (the Accord). Under the Accord, an inter-state work group is to be formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap and trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). All undertakings of the Accord are to be completed within 30 months after the effective date of the Accord, including the development of a proposed cap and trade agreement and model rule within 12 months.

 

The United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible

 

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post-2012 international actions to further address climate change. The United States is expected to participate in this process. Recommendations will be reviewed at the United Nations Framework Convention on Climate Change meeting in 2009.

 

At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

 

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 as an asset. Exelon believes that the significance of its low-GHG emission profile can only grow as policymakers take action to address global climate issues.

 

Despite Exelon’s low GHG emission intensity and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon announced on May 6, 2005 that it has established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. The 8% reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon will incorporate recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in activities that produce fewer GHG emissions. Exelon made this pledge under the U.S. Environmental Protection Agency’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. As of December 31, 2007, Exelon expects to achieve its 2008 voluntary GHG reduction goal through its 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. The anticipated cost of achieving the voluntary GHG emissions reduction goal is not expected to have a material effect on Exelon’s future competitive position, results of operations, earnings, financial position or cash flows.

 

Renewable and Alternative Energy Portfolio Standards

 

Approximately 29 states have adopted some form of renewable portfolio standard (RPS) legislation. 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.

 

Upon enactment of the Settlement Legislation in August 2007, Illinois electric utilities became subject to newly mandated increases in energy efficiency and renewable energy standards and are now required to use cost-effective energy efficiency and demand response resources to meet defined incremental annual program energy and demand savings goals. These goals generally call for reductions in delivered energy from the prior year for energy efficiency programs and for reductions in peak demand from the prior year for eligible customers. The goals are subject to rate impact caps each year. Utilities will be allowed current recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. Failure to comply with the energy efficiency and demand response requirements in the Settlement Legislation would result in ComEd being subject to penalties and other charges. In November 2007, pursuant to these requirements, ComEd filed its initial Energy Efficiency and Demand Response Plan with the ICC. This plan begins June 1, 2008, and is designed to meet the first three years of the Settlement Legislation’s energy efficiency and demand response goals, including reductions in delivered energy and in ComEd’s supply customers’ peak demand.

 

The Settlement Legislation also requires 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

 

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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. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15th year. In March 2005, the PAPUC issued its first implementation order related to the AEPS. In this order, the PAPUC established a schedule for Tier I and Tier II resources with year one covering the period June 1, 2006 through May 31, 2007. During year one, compliance with the Tier I and Tier II requirements began on February 28, 2007.

 

Tier I resources include: solar photovoltaic energy, wind power, low-impact hydro, geothermal energy, biologically derived methane gas, fuel cells, biomass energy and coal mine methane. A small percentage of the Tier I requirements must be met specifically by solar photovoltaic technologies. Tier II resources include: waste coal, distributed generation systems, demand side management, large-scale hydropower, municipal solid waste and several other technologies.

 

The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their transition period during which CTCs or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s transition period, this exemption no longer applies and compliance by the electric distribution company is required. PECO’s transition period expires December 31, 2010. PECO’s mandatory obligation to comply with the requirements of the AEPS Act begins upon the expiration of its generation rate cap on December 31, 2010. At this point in time, it is not certain that sufficient Tier I and solar renewable resources will be available in the market. If sufficient resources are not available in the market for electric distribution companies to meet their requirements, the PAPUC has the ability to make a force majeure determination to either reduce or remove the requirements under the AEPS Act.

 

In the first year after the end of an electric distribution company’s cost recovery period, the AEPS Act provides for cost recovery on a full and current basis pursuant to an automatic energy adjustment charge as a cost of generation supply. The banking of credits from voluntary purchases of Tier I and Tier II sources by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary purchases under the AEPS Act are deferred as a regulatory asset by the electric distribution company and are fully recoverable at the end of the cost recovery period, also pursuant to the automatic energy adjustment clause as a cost of generation supply.

 

In March 2007, PECO filed a request with the PAPUC for approval to acquire and bank up to 450,000 non-solar Tier I Alternative Energy Credits (equivalent to up to 240 MWs of electricity generated by wind) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance following the completion of its restructuring period. PECO proposed that all of the costs it incurs in connection with such procurement prior to 2011 be deferred as a regulatory asset with a return on the unamortized balance in accordance with the AEPS Act. Those costs, and PECO’s AEPS Act compliance costs incurred thereafter, would be recovered through a reconcilable ratemaking mechanism as contemplated by the AEPS Act. Pursuant to the AEPS Act, all deferred costs will be recovered from customers in 2011. Additionally, all AEPS related costs incurred after 2010 are recoverable from customers on a full and current basis. On December 20, 2007, the PAPUC approved PECO’s proposal to begin the procurement of alternative energy credits in fulfillment of Pennsylvania’s AEPS Act.

 

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While Generation is not directly affected by the AEPS Act from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some effect on 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.

 

Costs of Environmental Remediation

 

At December 31, 2007, Exelon, Generation, ComEd and PECO had accrued $132 million, $14 million, $77 million and $41 million, respectively, for various environmental investigation and remediation alternatives. Exelon, ComEd and PECO have recorded regulatory assets of $96 million, $66 million and $30 million, respectively, related to the recovery of MGP remediation costs. See Notes 19 and 20 of the Combined Notes to Consolidated Financial Statements for further detail.

 

The amounts to be expended in 2008 at Exelon, Generation, ComEd and PECO for compliance with environmental requirements is expected to total approximately $19 million, $1 million, $10 million and $8 million, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

 

Managing the Risks in the Business

 

Exelon, Generation, ComEd and PECO have considered the business challenges facing them and have adopted certain risk management activities. The Registrants recognize that their risk management activities address only certain of the challenges facing the Registrants and that those activities may not be effective in all circumstances. A discussion of the risks to which the Registrants’ businesses are subject and the potential consequences of those risks are contained in ITEM 1A. Risk Factors. On a continuing basis, the Registrants evaluate the challenges of their businesses and their ability to identify and mitigate these risks.

 

Generation

 

Nuclear capacity factors and refueling outages. Capacity factors, which are significantly affected by the number and duration of 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.

 

Generation continues to aggressively manage its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s short and long-term supply commitments and Power Team trading activities. Also, 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.

 

Adequacy of funds to decommission nuclear power plants. Generation has an obligation to decommission its nuclear power plants following their retirement from service. The ICC permitted ComEd through 2006, and the PAPUC permits PECO to collect funds, from their customers, which are deposited in nuclear decommissioning trust funds maintained by Generation. Beginning in 2008, PECO will be recovering approximately $29 million annually for nuclear decommissioning. It is anticipated that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years, subject to certain limitations, to reflect changes in cost estimates and decommissioning trust fund performance. These trust funds, together with earnings thereon, will be

 

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used to decommission such nuclear facilities. Decommissioning expenditures are expected to occur primarily after the plants are retired. Certain decommissioning costs are currently being incurred; however these current amounts are not considered material. In order to ensure adequate funding, Generation develops its decommissioning trust fund investment strategy based on an estimate of the timing and costs associated with nuclear decommissioning. To the extent that actual decommissioning activities result in higher costs or are incurred in the nearer term, Generation may not have sufficient funds to pay for decommissioning. To fund future decommissioning costs, Generation held $6.8 billion of investments in trust funds at December 31, 2007.

 

On December 11, 2007, Generation entered into an Asset Sale Agreement with EnergySolutions, Inc. and its affiliates, including ZionSolutions, whereby, upon completion of the agreement following the satisfaction of a number of closing conditions, Generation will transfer to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in nuclear decommissioning trusts (approximately $870 million). In consideration for Generation’s transfer of those assets, ZionSolutions will assume decommissioning and other liabilities associated with Zion Station.

 

See Note 13 of the Combined Notes to Consolidated Financial Statements for further details on nuclear decommissioning and trust funds.

 

Credit risk. In order to evaluate the viability of Generation’s counterparties, Generation has implemented credit risk management procedures designed to mitigate the risks associated with these transactions. These policies include counterparty credit limits and, in some cases, require deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation attempts to enter into enabling agreements that allow for payment netting with its counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross-product netting. To the extent that a counterparty’s credit limit and letter of credit thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

 

Extreme weather. Generation 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.

 

Wholesale energy market prices. 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 2008 and 2009 and, with the ComEd swap arrangement, also for 2010 into 2013. However, except for the ComEd swap arrangement, Generation is exposed to relatively greater commodity price risk beyond 2009 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 well. Generation has estimated a greater than 90% economic and cash flow hedge ratio for 2008 for its energy marketing portfolio.

 

Commodity prices. Generation’s Power Team manages the output of Generation’s assets and energy sales to optimize value and reduce the volatility of Generation’s earnings and cash flows.

 

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Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures.

 

Further, the supply markets for coal, natural gas and the uranium and services needed for nuclear fuel assemblies, which are used to operate the generating facilities, are subject to price fluctuations and availability restrictions. While it is not possible to predict the ultimate cost or availability of the commodities, Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate some of the price risk associated with these commodities.

 

ComEd and PECO

 

Post-transition rates. ComEd engaged extensively in the regulatory and legislative process related to the end of its transition period to manage the risk that it would not be able to pass through its power purchase costs to customers. In an effort to mitigate this risk, ComEd and Generation entered into the Settlement in July 2007 that was subsequently reflected in Settlement Legislation that ComEd believes will promote competition in Illinois’ retail markets and allow utilities to recover their approved supply costs while relieving pressure for rate freeze, generation tax, or other similar legislation. The Settlement stipulates that if legislation is enacted by the Illinois General Assembly prior to August 1, 2011 that freezes rates or imposes a generation tax, ComEd, Generation and other contributors to rate relief fund for Illinois electric customers could terminate their funding commitments made as part of the Settlement. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

While PECO has made no regulatory filings to date to revise its transmission and distribution rates established in 2000, PECO will continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. PECO will strive to ensure that future rate structures recognize the substantial improvements PECO has made, and will continue to make, in its transmission and distribution systems. PECO will also work to ensure that its post-2010 retail generation rates are adequate to cover its costs of obtaining electricity from its suppliers, which could include Generation.

 

Power supply risks. To effectively manage its obligation to provide power to meet its customers’ demand, ComEd has supplier forward contracts, effective January 2007, with various energy providers. ComEd is allowed by the ICC to recover from customers the cost of purchased electricity. Therefore, should an approved supplier default and ComEd be required to purchase replacement electricity, ComEd would be entitled to recover any incremental costs from customers. To fulfill a requirement of the Settlement and to mitigate ComEd’s exposure to the volatility of market prices, ComEd and Generation entered into a five-year financial swap arrangement, the effect of which is to cause ComEd to pay fixed prices and cause Generation to pay a market price for a portion of ComEd’s load. The financial swap contract dovetails with ComEd’s remaining auction contracts for energy, increasing in volume as the contracts expire over the next few years. Pursuant to the Settlement Legislation and the ICC-approved procurement model, this arrangement will be deemed prudent and ComEd will receive full cost recovery in rates.

 

To effectively manage its obligation to provide power to meet its customers’ demand, PECO has a full-requirements PPA with Generation that reduces PECO’s exposure to the volatility of customer demand and market prices through 2010.

 

Transmission congestion. ComEd and PECO have made, and expect to continue to make, significant capital expenditures to ensure the adequate capacity and reliability of their transmission systems. On an ongoing basis, PJM, in cooperation with ComEd and PECO, performs screening

 

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analyses based on forecasts of future transmission system conditions in order to determine system reinforcements needed to maintain the reliable and economic operation of both systems.

 

General Business

 

Security risk. 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 is working 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.

 

Interest rates. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants may also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest-rate swaps and/or treasury rate locks when deemed appropriate to lock in interest-rate levels in anticipation of future financings. See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk for further information.

 

Executive Officers of the Registrants as of February 7, 2008

 

Exelon

 

Name

   Age   

Position

Rowe, John W.

   62    Chairman, Chief Executive Officer, President and President, Exelon Generation

Clark, Frank M.

   62    Chairman and Chief Executive Officer, ComEd

O’Brien, Denis P.

   47    Executive Vice President and Chief Executive Officer and President, PECO

Crane, Christopher M.

   49    Executive Vice President and Chief Operating Officer, Exelon Generation

McLean, Ian P.

   58    Executive Vice President, Finance and Markets

Moler, Elizabeth A.

   59    Executive Vice President, Governmental and Environmental Affairs and Public Policy

Von Hoene Jr., William A.

   54    Executive Vice President and General Counsel

Zopp, Andrea L.

   51    Executive Vice President and Chief Human Resources Officer

Hilzinger, Matthew F.

   44    Senior Vice President and Chief Financial Officer

 

Generation

 

Name

   Age   

Position

Rowe, John W.

   62    Chairman, Chief Executive Officer and President, Exelon and President

Crane, Christopher M.

   49    Executive Vice President, Exelon, and Chief Operating Officer

Pardee, Charles G.

   48    Senior Vice President and Chief Nuclear Officer, Exelon Nuclear

Schiavoni, Mark A.

   52    Senior Vice President and President, Exelon Power

Cornew, Kenneth W.

   42    Senior Vice President, Exelon and President, Power Team

Hilzinger, Matthew F.

   44    Senior Vice President, Exelon and Chief Financial Officer

Veurink, Jon D.

   43    Vice President and Controller

 

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ComEd

 

Name

   Age   

Position

Clark, Frank M.

   62    Chairman and Chief Executive Officer

Mitchell, J. Barry

   60    President and Chief Operating Officer

Pramaggiore, Anne R.

   49    Executive Vice President Customer Operations, Regulatory and External Affairs

McDonald, Robert K.

   52    Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer

Hooker, John T.

   59    Senior Vice President, State Legislative and Governmental Affairs

Galvanoni, Matthew R.

   35    Vice President and Controller

 

PECO

 

Name

   Age   

Position

O’Brien, Denis P.

   47    Executive Vice President, Exelon, Chief Executive Officer and President

Barnett, Phillip S.

   44    Senior Vice President and Chief Financial Officer

Adams, Craig L.

   55    Senior Vice President and Chief Operating Officer

Crutchfield, Lisa

   44    Senior Vice President, Regulatory and External Affairs

Galvanoni, Matthew R.

   35    Vice President and Controller

 

Each of the above executive officers holds such office at the discretion of the respective company’s board of directors 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 2007 and has served as Chairman and Chief Executive Officer of Exelon since 2002.

 

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; Senior Vice President, Exelon, and Executive Vice President of Exelon Energy Delivery and President ComEd from 2003 to 2004; and Senior Vice President Exelon Energy Delivery and President ComEd from 2002 to 2003. 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; and Executive Vice President of PECO from 2002 to 2003.

 

Prior to his election to his listed position, Mr. Crane was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear from 2004 to 2007; and Chief Operating Officer, Exelon Nuclear from 2003 to 2004; and Senior Vice President for Exelon Nuclear from 2000 to 2003.

 

Prior to his election to his listed position, Mr. McLean was Executive Vice President, Exelon and President, Power Team from 2002 to 2008.

 

Ms. Moler was elected to her listed position in 2002.

 

Prior to his election to his listed position, Mr. Von Hoene was Senior Vice President and General Counsel, Exelon from 2006 to 2008; Senior Vice President and acting General Counsel, Exelon from 2005 to 2006; Senior Vice President and Deputy General Counsel, Exelon from 2004 to 2005; and Vice President and Deputy General Counsel, Exelon from 2002 to 2004.

 

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Prior to her election to her listed position, Ms. Zopp was Senior Vice President, Exelon and Chief Human Resources Officer from 2007 to 2008; Senior Vice President, Human Resources, Exelon from 2006 to 2007; Senior Vice President, General Counsel and Corporate Secretary, Sears Holding Corporation from 2003 to 2005; Vice President, Deputy General Counsel, Sara Lee Corporation from 2000 to 2003.

 

Prior to his election to his listed position, Mr. Hilzinger was Senior Vice President, Exelon and Corporate Controller from 2005 to 2008; 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. Pardee was Senior Vice President and Chief Operating Officer, Exelon Nuclear from 2005 to 2007; Senior Vice President Engineering and Technical Services from 2004 to 2005; Senior Vice President Nuclear Services from 2003 to 2004; and Senior Vice President of the Mid-Atlantic Regional Operating Group from 2002 to 2003.

 

Prior to his election to his listed position, Mr. Schiavoni was Vice President of Exelon Power from 2003 to 2004; and Vice President of Northeast Operations of Exelon Power from 2002 to 2003.

 

Prior to his election to his listed position, Mr. Cornew held the following positions in the Power Team division of Exelon Generation: Senior Vice President, Trading and Origination from 2007 to 2008; Senior Vice President, Power Transactions and Wholesale Marketing from 2004 to 2007; Vice President, Portfolio Management from 2003 to 2004; and Vice President, Long-Term Transactions from 2000 to 2003.

 

Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP from 2000 to 2003.

 

Prior to his election to his listed position, Mr. Mitchell was President of ComEd from 2005 to 2007; Senior Vice President and Chief Financial Officer of Exelon during 2005; and Senior Vice President and Treasurer of Exelon from 2002 to 2005.

 

Prior to her election to her listed position, Ms. Pramaggiore was 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. McDonald was Senior Vice President of Financial Planning and Chief Risk Officer of Exelon during 2005; and Vice President of Financial Planning and Risk Management of Exelon from 2002 to 2005.

 

Prior to his election to his listed position, Mr. Hooker served as Senior Vice President, ComEd, Legislative and External Affairs and Exelon Energy Delivery Real Estate and Property Management from 2003 to 2005. Mr. Hooker served as Vice President Exelon Energy Delivery Property Management and ComEd Legislative and External Affairs during 2003; and Vice President Distribution Services and Public Affairs from 1999 to 2003.

 

Prior to his election to his listed positions, Mr. Galvanoni was Director of Financial Reporting and Analysis, Exelon during 2006. Mr. Galvanoni has also served as Director of Accounting and Reporting, Generation from 2004 to 2005 and was Director of External Reporting, Exelon from 2002 to 2003.

 

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; and Chief Financial Officer of GE Capital TIP Intermodal Services from 2001-2003.

 

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Prior to his election to his listed position, Mr. Adams was Senior Vice President and Chief Supply Officer, Exelon Business Services Company, LLC from 2004 to 2007; and Senior Vice President, Exelon Energy Delivery Support Services from 2002 to 2004.

 

Prior to her election to her listed position, Ms. Crutchfield served as Vice President, Regulatory and External Affairs at PECO from 2003 to 2007; and Vice President and General Manager at TIAA-CREF Southern Service Center from 2000 to 2002.

 

ITEM 1A. RISK FACTORS

 

The Registrants each operate in a market and regulatory environment that involves significant risks, many of which are beyond their control. The Registrants’ management regularly evaluates the most significant risks of the Registrants’ businesses and discusses those risks with the Risk Oversight Committee of the Exelon Board of Directors and the ComEd and PECO Boards of Directors. The risk factors below, as well as the risks discussed in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Liquidity and Capital Resources, may adversely affect the Registrants’ results of operations and cash flows and the market prices of their publicly traded securities. While each of the Registrants believes it has identified and discussed the key risk factors affecting its business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect its performance or financial condition.

 

General Business

 

The following risk factors may adversely impact several or all of the Registrants’ results of operations and cash flows.

 

Exelon’s generation and energy delivery businesses are highly regulated. Fundamental changes in regulation could disrupt Exelon’s business plans and adversely affect its operations and financial results.

 

Substantially all aspects of the businesses of Exelon and its subsidiaries are subject to comprehensive Federal or state regulation. Further, Exelon’s operating results and cash flows are heavily dependent upon the ability of its generation business to sell power at market-based rates, as opposed to cost-based or other similarly regulated rates, and the ability of its energy delivery businesses to recover their costs for purchased power and their costs of distribution of power to their customers. In its business planning and in the management of its operations, Exelon must address the effects of regulation of its businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, ratemaking jurisdictions and taxing authorities. In particular, state and Federal 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. Although Exelon does not agree with this position, the effectiveness of Exelon in meeting these challenges affects its operating results and cash flows and the value of its generation and energy delivery assets. Fundamental changes in the nature of the regulation of Exelon’s businesses would require changes in its business planning models and could adversely affect its operating results and the value of its assets.

 

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The Settlement Legislation enacted in Illinois 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.

 

The Settlement Legislation enacted in Illinois in August 2007 contemplates approximately $1 billion of rate relief to Illinois electric customers. The Settlement Legislation will also require several other changes to the electric industry in Illinois, including the creation of a new state power agency, an alternative method of purchasing power for consumers and a mandated increase in energy efficiency and renewable energy standards. This Settlement Legislation was the result of the Settlement reached by ComEd, Generation, and other utilities and generators in Illinois with various representatives of the State of Illinois concluding months of extensive discussions and following various bills that had been proposed by the Illinois House of Representatives and Senate in an attempt 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 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 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 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 and cash flows.

 

Results of operations may be negatively affected by increasing costs.

 

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 which 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.

 

Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets, which then could require significant additional funding.

 

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations to decommission Generation’s nuclear plants and under Exelon’s pension and postretirement benefit plans. The Registrants have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below the Registrants’ projected return rates. For example, certain investments within the trusts hold underlying securities in subprime mortgage related assets. Due to recent market developments, including a series of rating agency downgrades of subprime U.S. mortgage-related assets, the fair value of these subprime-related investments may decline. Exelon expects that market conditions will continue to evolve, and that the fair value of Exelon’s subprime-related investments may frequently change. A decline in the market value of the assets, as was experienced in prior periods, may increase the funding requirements of the obligations to decommission Generation’s nuclear plants and under Exelon’s pension and postretirement benefit

 

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plans. Additionally, changes in interest rates affect the liabilities under Exelon’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, 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 benefit plans. If the Registrants are unable to successfully manage the decommissioning trust funds and benefit plan assets, their results of operation and financial position could be negatively affected.

 

Exelon’s holding company structure could limit its ability to pay dividends.

 

Exelon is a holding company with no material assets other than the investment in its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Exelon’s ability to pay dividends on its common stock depends on the payment to it of dividends by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. 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. In addition, 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 a dividend after provision is made for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. During 2006 and 2007, ComEd did not pay any dividend. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer restrictions.

 

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards.

 

As a result of the Energy Policy Act, 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. These standards, which previously were being applied on a voluntary basis, became mandatory on June 18, 2007. 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 new 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 sanctions, including substantial monetary penalties.

 

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters.

 

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

 

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Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies 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.

 

Generation will incur material costs of compliance if regulations under Section 316(b) of the Clean Water Act require retrofitting of cooling water intake structures at power plants owned by Generation. In addition, the amounts of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to operate the plant after the Section 316(b) 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 contribute to a fund with a material contribution 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 19 of the Combined Notes to Consolidated Financial Statements for further information.

 

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

 

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 are likely to evolve in the future. If these plans become effective, Exelon and Generation may incur material costs to either further limit the GHG emissions from its operations or in procuring emission allowance credits. For more information regarding climate change, see “Global Climate Change” in ITEM 1 of this Form 10-K.

 

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

 

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 electric generation, 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. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect Exelon’s revenues or restrict its future growth. Instability in the financial markets as a result of terrorism, war, natural disasters, credit crises, recession or other factors also may affect Exelon’s results of operations and its

 

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ability to raise capital. In addition, the implementation of security guidelines and measures have resulted in and are expected to continue to result in 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. See “Environmental Regulation” in ITEM 1 of this Form 10-K for further information.

 

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ results of operations.

 

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 becomes currently payable. As of December 31, 2007, Exelon’s and ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $992 million. If the deferral were successfully challenged by the IRS, it could negatively affect Exelon’s and ComEd’s results of operations by up to $167 million (after tax) related to interest expense. The timing of the final resolution of this matter is unknown. See Note 12 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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, including the potential phase-out of tax credits for the sale of synthetic fuel produced from coal, in the financial statements. Exelon has not recorded a valuation allowance for $15 million of deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. See Notes 1 and 12 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Increases in taxes and fees. Due to the revenue needs of the states and jurisdictions in which the Registrants operate, various tax and fee increases may be proposed or considered. The Registrants cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, or, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. If enacted, these changes could increase tax expense and could have a negative impact on the Registrants’ results of operations and cash flows.

 

In August 2007, the Governor of Illinois signed Illinois SB 1544 into law, which became effective January 1, 2008. SB 1544 provides for market-based sourcing of the generation and sale of electricity for Illinois income tax purposes. This legislation will affect the method in which sales of electricity are apportioned in the determination of Illinois income tax. The language in SB 1544 is broad based and undefined and expressly provides that the sourcing of electricity may be subject to rules prescribed by the Illinois Department of Revenue. Based on the limited statutory definitions and legislative intent available at this time, Exelon cannot reasonably estimate the impact on its Illinois income tax. The Illinois Department of Revenue is expected to issue guidance implementing this legislation. As guidance is released, Exelon will further assess the impact that SB 1544 may have on its financial position, results of operations and cash flows. On January 13, 2008, Illinois enacted SB 783 amending the language of SB 1544 to expressly provide that the Department of Revenue “shall” establish utility sourcing regulations.

 

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

 

Exelon and certain of its subsidiaries 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 of these guaranteed obligations by the third parties, Exelon and its subsidiaries could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results or financial condition of Exelon and its subsidiaries. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding guarantees.

 

The Registrants may make acquisitions that do not achieve the intended financial results.

 

The Registrants may continue to make investments and pursue mergers and acquisitions that fit their strategic objectives and improve their financial performance. It is possible that FERC or the state public utility commissions may impose certain other restrictions on the investments that the Registrants may make. 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.

 

Failure to attract and retain an appropriately qualified workforce may negatively impact the Registrants’ results of operations.

 

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 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.

 

Generation

 

Market Transition Risks

 

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.

 

Generation currently provides power under supplier forward contracts with ComEd to supply up to 35% of ComEd’s electricity supply requirements and a PPA with PECO to meet 100% of PECO’s electricity supply requirements. Consequently, Generation is highly dependent on ComEd’s and PECO’s continued payments under these supplier forward contracts and the PPA and would be adversely affected by negative events affecting these agreements, including the non-performance or a 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.

 

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

 

Generation’s business may be negatively affected by the restructuring of the energy industry.

 

RTOs. 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 among the markets. Approximately 83% 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 rising costs of energy that are reflected through wholesale markets.

 

Competitive Electric Generation Suppliers. Because retail customers in both Pennsylvania and Illinois can switch from PECO or ComEd to a competitive electric generation supplier for their energy needs, planning to meet Generation’s obligation to supply PECO with all of the energy PECO needs to fulfill its default service obligation and to provide the supply needed to serve Generation’s share of the ComEd load 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 PECO and/or ComEd 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

 

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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 PECO and /or ComEd load that Generation must serve will be lower than anticipated, which could, if market prices have decreased, caused Generation to lose opportunities in the market.

 

Generation may be negatively affected by possible Federal legislative or regulatory actions that could weaken competition in the wholesale markets or affect pricing rules in the RTO markets.

 

The criticism of restructured electricity markets, which escalated during 2006 as retail rate freezes expired and prices of electricity increased with rising fuel prices, is expected to continue in 2008. 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. 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 convened a series of public conferences during 2007 to address the issues surrounding electric competition. FERC issued an Advanced Notice of Proposed Rulemaking (ANOPR) on Wholesale Competition in Regions with Organized Electric Markets on June 22, 2007. Exelon filed comments on September 14, 2007. On December 17, 2007, a number of advocacy groups filed comments requesting that the scope of the ANOPR be expanded to address the current structure and practices of the RTO-administered markets, which the advocacy groups contend have led to unjust and unreasonable rates. The outcome of this FERC rulemaking process could significantly affect Generation’s results of operations.

 

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 requires a market power update filing by Generation, ComEd and PECO, which was made on January 14, 2008. The application of the Final Rule 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.

 

Generation may not be able to effectively respond to competition in the energy industry.

 

Generation’s financial performance depends in part on its ability to respond to competition in the energy industry. As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers have become prevalent in the wholesale power industry. The new generating facilities of these market entrants may be more efficient than Generation’s facilities. Additionally, the introduction of new technologies could lower prices and have an adverse effect on Generation’s results of operations or financial condition.

 

Generation may not be able to effectively respond to increased demand for energy.

 

Generation’s financial growth depends in part on its ability to respond to increased demand for energy. As the 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 the Illinois and Pennsylvania 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. Further, construction of new generating

 

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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.

 

Nuclear Operations Risks

 

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

 

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 generate 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 generate energy from its nuclear stations.

 

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%. The number of refueling outages, including the AmerGen plants and the co-owned plants, was 9 in 2007 with 12 planned for 2008. The projected total non-fuel capital expenditures for the nuclear plants operated by Generation will increase in 2008 compared to 2007 by approximately $62 million as Generation continues to invest in equipment upgrades to ensure safe reliable operations and as a result of two additional planned refueling outages at nuclear plants operated by Generation in 2008 compared to 2007. Total operating and maintenance expenditures for the nuclear plants operated by Generation are expected to increase by approximately $99 million in 2008 compared to 2007 as a result of inflationary cost increases as well as the aforementioned two additional planned refueling outages in 2008 compared to 2007.

 

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 been identified as having a limited number of fuel performance issues. Remediation actions, including those required to address performance issues, 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 total cost of these remediation procedures.

 

Spent nuclear fuel storage. The approval of a national repository for the storage of spent nuclear fuel, 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 spent nuclear fuel, 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 availability of a repository for spent nuclear fuel may adversely affect Generation’s ability to fully decommission the nuclear units.

 

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Environmental risk. If application of the Section 316(b) regulations establishing a national requirement for reducing the adverse impacts from the entrainment and impingement of 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. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to operate the plant after the 316(b) matter is ultimately resolved.

 

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 spent nuclear fuel not be developed, the unavailability of a repository for spent nuclear fuel 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 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 others, Salem Units 1 and 2, from which Generation receives its share of the plant’s output, Generation is dependent on the operational performance of the co-owner operator.

 

Nuclear accident risk. Although the safety record of nuclear reactors, including Generation’s, generally has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident may exceed Generation’s resources, including insurance coverages, 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 (currently $300 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 $10.76 billion limit for a single incident.

 

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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. Generation’s portion of the NEIL distribution for 2007 was $43 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statement of Operations. 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 retired units) 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 current licensed life.

 

Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to provide other means of funding its decommissioning obligations.

 

Other Operating Risks

 

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.

 

Generation depends on nuclear fuel, coal and natural gas to operate its generating facilities. Nuclear fuel is obtained through long-term uranium concentrate inventory and supply contracts, contracted conversion services, contracted enrichment services and fuel fabrication services. Coal is procured for coal-fired plants through annual, short-term and spot-market purchases. Natural gas is procured for gas-fired plants through annual, monthly and spot-market purchases. The supply markets for nuclear fuel, coal and natural gas 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 predict the ultimate cost or availability of these commodities.

 

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

 

A significant portion of Generation’s power portfolio is used to provide power under a long-term PPA with PECO and supplier forward contracts with ComEd. To the extent portions of the portfolio are not needed for that purpose, Generation’s output is sold on the wholesale market. To the extent its portfolio is not sufficient to meet the requirements of ComEd and PECO 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 ComEd and PECO, manage its power portfolio and effectively handle the changes in the wholesale power markets.

 

Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations.

 

Generation fulfills its energy 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

 

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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 are not used to meet its long-term supply commitments, including its commitments to ComEd and PECO, 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 supplied would be supplied from generating stations fueled by fossil fuels, primarily natural gas. Consequently, the open-market wholesale price of electricity likely reflects the cost of natural gas plus the cost to convert natural gas to electricity. Therefore, changes in the supply and cost of natural gas generally affect the open market wholesale price of electricity.

 

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, energy or fuel 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 power 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 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 accounts receivable balance, as well as the loss from the resale of energy previously committed to serve the customer.

 

Risk of Credit Downgrades. Generation’s trading business is required to meet credit quality standards. If Generation were to lose its investment grade credit 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. If Generation had lost its investment grade credit rating as of December 31, 2007, it would have been required to provide approximately $830 million in collateral.

 

Immature 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, as was experienced in California in 2000, could adversely affect Generation’s business.

 

Hedging. 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.

 

Weather. Generation’s operations are 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 requirements. 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. 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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Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities.

 

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

 

Generation’s business is capital intensive and the costs of capital projects may be significant.

 

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. For example, Generation is considering building a new nuclear plant in southeast Texas and plans to expend substantial resources to the evaluation, development and permitting of the project, site acquisition and long-lead procurement; substantial additional resources would be required for the construction of the plant if a decision is made to build. Achieving the intended benefits of a large capital project of this type is subject to a number of uncertainties. Generation’s results of operations could be adversely affected if Generation were unable to effectively manage its capital projects.

 

ComEd

 

Exelon’s and ComEd’s goodwill may become impaired, which would result in write-offs of the impaired amounts.

 

Exelon and ComEd both had approximately $2.6 billion of goodwill recorded at December 31, 2007 in connection with the PECO/Unicom merger. Under accounting principles generally accepted in the United States (GAAP), goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an annual analysis prescribed by SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, such as the impairments recorded during 2006 and 2005, the amount of the impaired goodwill will be written-off and expensed, reducing equity.

 

There is a possibility that additional goodwill may be impaired at ComEd, and at Exelon, in 2008 or later periods. 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, market prices for power, results of ComEd’s rate proceedings, operating and capital expenditure requirements and other factors, some not yet known. Such a potential impairment charge could have a material impact on Exelon’s and ComEd’s operating results but will have no impact to either Exelon’s or ComEd’s cash flows.

 

See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

 

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PECO

 

PECO could be subject to higher transmission operating costs in the future as a result of PJM’s regional transmission expansion plan (RTEP) and the rate design between PJM and MISO.

 

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 and that costs of new facilities less than 500 kV to be allocated to the beneficiaries of the new facilities. FERC stated that PJM’s stakeholders should develop a standard method for allocating costs of new transmission facilities lower than 500 kV. PECO cannot estimate the longer-term impact on its results of operations and cash flows because of the uncertainties relating to what new facilities will be built and the cost of building those facilities.

 

In 2007, PECO and almost all other transmission owners in PJM and the Midwest ISO (MISO), as directed by a FERC order issued in 2004, filed with FERC to continue the existing transmission rate design between PJM and MISO. Other transmission owners and certain other parties have filed protests urging FERC to reject the filing. On January 31, 2008, FERC accepted the filing. An additional complaint was filed asking FERC to substitute a rate design that allocates the costs of all existing and new transmission facilities at 345 kV and above across PJM and MISO. On January 31, 2008, FERC denied the complaint. PECO cannot predict the outcome of any possible requests for rehearing or appeals of these proceedings nor the impact that the ultimate rate design will have on its transmission operating costs.

 

PECO may be subject to the risk of a legislative or regulatorily mandated requirement to purchase Philadelphia Gas Works (PGW).

 

PGW is a municipal gas utility owned by the City of Philadelphia that provides service almost exclusively within Philadelphia. A Pennsylvania state legislator submitted legislation to the Pennsylvania General Assembly that would provide the PAPUC with the authority to investigate PGW’s fitness to provide gas service and, if deemed unfit, to require a qualified public utility to purchase PGW’s gas assets. If such legislation is enacted, PECO, with a natural gas service territory contiguous to and an electric service territory that includes Philadelphia, could be subject to a proceeding in which efforts are made to require PECO to purchase PGW’s gas assets. While PECO believes that such a forced purchase would be unlawful, such a proceeding could expose PECO potentially to significant economic and political risk.

 

The effect of higher purchased gas cost charges to customers may decrease PECO’s results of operations and cash flows.

 

Gas rates charged to 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. PECO’s cash flows can be impacted by differences between the time period when natural gas is purchased and the ultimate recovery from customers. When 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, increased purchased natural gas cost charges to customers also may result in increased bad debt expense from an increase in the number of uncollectible customer balances.

 

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ComEd and PECO

 

The following risk factors separately apply to both ComEd and PECO as further noted below.

 

Rising rates or the expectation of rising rates can stimulate legislative or regulatory action aimed at restricting or controlling those rate increases, which can create uncertainty affecting planning, costs and results of operations.

 

Large increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those rates. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs may be reflected in reduced liquidity, as suppliers tighten payment terms, and increased costs of financing, as lenders demand increased compensation or collateral security to accept such risks.

 

Legislators or regulators may respond to current or anticipated increases in utility rates by enacting laws or regulations aimed at restricting or controlling those rates that may adversely affect the utility’s ability to recover its costs, maintain adequate liquidity and address capital requirements.

 

Legislators and regulators may focus on immediate forms of rate relief, such as rate increase moderation or freezes and may pursue initiatives that affect the manner in which utilities procure energy, recover costs or interact with customers. Those measures could include the imposition or continuation of rate caps, rate moderation, installation of smart metering technology, fees on consumption, and various measures promoting conservation, energy efficiency and renewable energy initiatives. Such measures may reduce revenues, increase operating costs and mandate initiatives requiring additional capital investments or changes in the way utilities conduct business. These initiatives can be accompanied by additional costs for which recovery may not be certain as well as incentives for compliance and penalties for noncompliance. Restrictions affecting rates and revenues, and the ability to recover costs, could affect liquidity and the ability to maintain reliable delivery systems and make capital improvements. Inadequate cost recovery could lead to lowered credit ratings, reduced access to capital markets, increased financing costs, lower flexibility due to constrained financial resources, collateral security requirements, and possible bankruptcy.

 

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.

 

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 and the recovery of MGP remediation costs.

 

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In certain instances, ComEd and PECO may agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are 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 will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR and default service obligations, in the case of ComEd, for ComEd’s customers with demand of 100kW or less who have not chosen a competitive electric generation supplier and, for a limited period, for certain customers with higher demands, and, in the case of PECO, for all PECO customers, 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.

 

The impact of not meeting the criteria of Financial Accounting Standards Board Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71) could be material to ComEd and PECO.

 

As of December 31, 2007, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria of SFAS No. 71. 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 SFAS No. 71 could be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2007, the extraordinary gain could have been as much as $2.9 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2007, the extraordinary charge could have been as much as $3.0 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 other comprehensive income (before taxes) of up to $1.2 billion and $74 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 would be significant and at least partially offset the extraordinary gain discussed above. A write-off of regulatory assets and liabilities also could limit the ability of ComEd and PECO to pay dividends under Federal and state law. See Notes 1, 4, 8 and 20 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.

 

Increases in customer rates and the impact of other economic downturns may lead to a greater amount of uncollectible customer balances for ComEd and PECO. Future recoverability of any additional uncollectible customer balances is subject to regulatory proceedings.

 

ComEd’s customer rates for delivery service and procurement of electricity increased in 2007 with the end of the legislatively mandated transition and rate freeze period in Illinois. The Settlement

 

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Legislation prohibits utilities from terminating electric service to an Illinois residential space-heating customer due to nonpayment between December 1 of any year through March 1 of the following year. With respect to PECO, its gas rates may change quarterly based on market conditions which may lead to higher prices. Additionally, PECO’s electric rates have increased in recent years as permitted under the 1998 restructuring settlement and the related PECO/Unicom Merger Settlement Agreements. Due to increased rates, limitations on service termination, and the future collection of deferred balances, ComEd and PECO may experience a greater amount of uncollectible customer balances.

 

Mandatory energy conservation and RPS legislation could negatively affect the costs and cash flows of ComEd and PECO.

 

Federal legislation mandating specific energy conservation measures or changes to existing laws requiring the use of renewable and alternate fuel sources, such as wind, solar, biomass and geothermal, could significantly impact ComEd and PECO if timely recovery is not allowed. The impact could include increased costs for renewable energy credits and purchased power as well as significant increases in capital expenditures. There is no certainty that ComEd or PECO would be permitted sufficient or timely recovery of related costs in rates. Furthermore, energy conservation measures could lead to a decline in energy consumption and ultimately the revenues of ComEd and PECO. ComEd and PECO will continue to monitor RPS and energy conservation developments at the Federal and state levels.

 

For additional information, see ITEM 1. Business “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards”.

 

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

 

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.

 

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.

 

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. Those failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction, 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.

 

The effects of weather and the related impact on electricity and gas usage may decrease ComEd’s and PECO’s results of operations.

 

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

 

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heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, ComEd and PECO typically report higher revenues in the third quarter of the fiscal year. However, 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 operations.

 

ComEd’s and PECO’s businesses are capital intensive and the costs of capital projects may be significant.

 

ComEd’s and PECO’s businesses are capital intensive and require significant investments in internal infrastructure projects. ComEd’s and PECO’s results of operations and financial condition could be adversely affected if they are unable to effectively manage their own respective capital projects, if they are unable to raise the necessary capital, or if they do not receive full recovery of their own respective capital costs through future regulatory proceedings in a timely manner.

 

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, 2007:

 

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   2,295  

Oyster Creek

  Forked River, NJ   1     Uranium   Base-load   625  

Peach Bottom

  Peach Bottom Twp., PA   2   50.00   Uranium   Base-load   1,139  (e)

Quad Cities

  Cordova, IL   2   75.00   Uranium   Base-load   1,303  (e)

Salem

  Hancock’s Bridge, NJ   2   42.59   Uranium   Base-load   981 (e)

Three Mile Island

  Londonderry Twp, PA   1     Uranium   Base-load   837  
               
            16,969  

Fossil (Steam Turbines)

         

Conemaugh

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

Cromby 1

  Phoenixville, PA   1     Coal   Intermediate   144  

Cromby 2

  Phoenixville, PA   1     Oil/Gas   Intermediate   201  

Eddystone 1, 2

  Eddystone, PA   2     Coal   Intermediate   588  

Eddystone 3, 4

  Eddystone, PA   2     Oil/Gas   Intermediate   760  

 

(continued on next page)

 

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Station

 

Location

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

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

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  

Fossil (Combustion Turbines)

         

Chester

  Chester, PA   3     Oil   Peaking   39  

Croydon

  Bristol Twp., PA   8     Oil   Peaking   386  

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   116  

Moser

  Lower Pottsgrove Twp., PA   3     Oil   Peaking   51  

New Boston

  South Boston, MA   1     Oil   Peaking   13  

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  
               
            1,449  

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   3  (e)

Schuylkill

  Philadelphia, PA   1     Oil   Peaking   3  
               
            14  

Hydroelectric

           

Conowingo

  Harford Co., MD   11     Hydroelectric   Base-load   572  

Muddy Run

  Lancaster, PA   8     Hydroelectric   Intermediate   1,070  
               
            1,642  
                 

Total

    124         24,808  
                 

 

(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 low-efficiency, quick response steam units, gas turbines, diesels and pumped-storage hydroelectric equipment normally used during the maximum load periods.

 

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(c) For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, 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.

 

The net generation capability available for operation at any time may be less due to regulatory restrictions, 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.

 

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, 2007 were as follows:

 

     

Voltage (Volts)

  

Circuit Miles

     
  

765,000

   90   
  

345,000

   2,621   
  

138,000

   2,872   
  

69,000

   149   

 

ComEd’s electric distribution system includes 43,335 circuit miles of overhead lines and 35,326 cable miles of underground lines.

 

First Mortgage and Insurance

 

The principal plants and 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.

 

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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.

 

Transmission and Distribution

 

PECO’s higher voltage electric transmission lines owned and in service at December 31, 2007 were as follows:

 

     

Voltage (Volts)

  

Circuit Miles

     
  

500,000

   188 (a)   
  

230,000

   541   
  

138,000

   156   
  

69,000

   182   

 

(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 12,933 circuit miles of overhead lines and 15,260 cable miles of underground lines.

 

Gas

 

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2007:

 

     Pipeline Miles

Transportation

   31

Distribution

   6,654

Service piping

   5,472
    

Total

   12,157
    

 

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 plants and 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.

 

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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 4 and 19 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 31, 2008, there were 661,220,392 shares of common stock outstanding and approximately 143,410 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:

 

     2007    2006
     Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter
   Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter

High price

   $ 86.83    $ 82.60    $ 79.38    $ 72.31    $ 63.62    $ 61.98    $ 58.86    $ 59.90

Low price

     73.76      64.73      68.67      58.74      57.83      56.74      51.13      52.79

Close

     81.64      75.36      72.60      68.71      61.89      60.54      56.83      52.90

Dividends

     0.440      0.440      0.440      0.440      0.400      0.400      0.400      0.400

 

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock during the fourth quarter of 2007.

 

Period

   Total Number of
Shares Purchased (a)
   Average Price
Paid per Share
   Total Number of
Shares Purchased
As Part of Publicly
Announced Plans
or Programs (b)
   Maximum Number
(or Approximate
Dollar Value) of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
 

October 1—October 31, 2007

   6,151    $ 76.41    —      (b )

November 1—November 30, 2007

   6,711      82.31    —      (b )
             

Total

   12,862      79.49    —      (b )
             

 

(a) Shares other than those purchased as a part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares.
(b) In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The 2004 share repurchase program has no specified limit and no specified termination date.
     In addition, on August 31, 2007, Exelon’s Board of Directors approved a share repurchase program for up to $1.25 billion of Exelon’s outstanding common stock. As part of its value return policy, Exelon uses share repurchases from time to time to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities. The related accelerated share repurchase agreement includes a pricing collar, which establishes a minimum and maximum number of shares that can be repurchased.
     On December 19, 2007, Exelon’s Board of Directors authorized a new share repurchase program of up to $500 million of Exelon’s outstanding common stock.
     See Note 17 of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s share repurchase programs.

 

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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 2002 through 2007.

 

This performance chart assumes:

 

   

$100 invested on December 31, 2002 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 31, 2008, Exelon held the entire membership interest in Generation.

 

ComEd

 

As of January 31, 2008, there were outstanding 127,016,519 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At January 31, 2008, in addition to Exelon, there were 269 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

 

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PECO

 

As of January 31, 2008, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were 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 II and ComEd Financing III (the Financing Trusts) that it will not declare dividends on any shares of its capital stock in the event

 

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that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to the Financing Trusts; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; 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 stock. At December 31, 2007, such capital was $2.8 billion and amounted to about 32 times the liquidating value of the outstanding preferred stock 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 PECO Energy Capital, L.P. (PEC L.P.) or PECO Energy Capital Trust IV (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, 2007, Exelon had retained earnings of $4.9 billion, including Generation’s undistributed earnings of $1,429 million, ComEd’s retained deficit of $(29) million consisting of an unappropriated retained deficit of $(1,639) million, partially offset by $1,610 million of retained earnings appropriated for future dividends and PECO’s retained earnings of $548 million.

 

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2007 and 2006:

 

     2007    2006

(per share)

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

Exelon

   $ 0.440    $ 0.440    $ 0.440    $ 0.440    $ 0.400    $ 0.400    $ 0.400    $ 0.400

 

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

 

     2007    2006

(in millions)

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

Generation

   $ 261    $ 1,431    $ 370    $ 295    $ 165    $ 122    $ 157    $ 165

PECO

     108      178      121      155      134      117      135      116

 

On December 19, 2007, the Exelon Board of Directors declared a regular quarterly dividend of $0.50 per share on Exelon’s common stock. The dividend is payable on March 10, 2008 to shareholders of record of Exelon at the end of the day on February 15, 2008. This dividend declaration was made by the Exelon Board of Directors under a value return policy that established a base dividend that Exelon expects will grow modestly over time. The value return policy contemplates the use of share repurchases from time to time, when authorized by the Board of Directors, to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities.

 

During 2007 and 2006, ComEd did not pay a dividend. This decision by the ComEd Board of Directors not to declare a dividend was the result of several factors, including ComEd’s need for a rate increase to cover existing costs and anticipated levels of future capital expenditures as well as the continued uncertainty related to ComEd’s regulatory filings as discussed in Note 4 of the Combined

 

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Notes to Consolidated Financial Statements. ComEd’s Board of Directors will assess ComEd’s ability to pay a dividend after 2007.

 

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 Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,  

in millions, except for per share data

   2007    2006    2005     2004     2003  

Statement of Operations data:

            

Operating revenues

   $ 18,916    $ 15,655    $ 15,357     $ 14,133     $ 15,148  

Operating income

     4,668      3,521      2,724       3,499       2,409  

Income from continuing operations

   $ 2,726    $ 1,590    $ 951     $ 1,870     $ 892  

Income (loss) from discontinued operations

     10      2      14       (29 )     (99 )

Income before cumulative effect of changes in accounting principles

     2,736      1,592      965       1,841       793  

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

     —        —        (42 )     23       112  
                                      

Net income (a), (b)

   $ 2,736    $ 1,592    $ 923     $ 1,864     $ 905  
                                      

Earnings per average common share (diluted):

            

Income from continuing operations

   $ 4.03    $ 2.35    $ 1.40     $ 2.79     $ 1.36  

Income (loss) from discontinued operations

     0.02      —        0.02       (0.04 )     (0.15 )

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

     —        —        (0.06 )     0.03       0.17  
                                      

Net income

   $ 4.05    $ 2.35    $ 1.36     $ 2.78     $ 1.38  
                                      

Dividends per common share

   $ 1.76    $ 1.60    $ 1.60     $ 1.26     $ 0.96  
                                      

Average shares of common stock outstanding—diluted

     676      676      676       669       657  
                                      

 

(a) The changes between 2007 and 2006; 2006 and 2005; and 2005 and 2004 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.
(b) Change between 2004 and 2003 was primarily due to the impairment of Boston Generating, LLC long-lived assets of $945 million in 2003.

 

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     December 31,

in millions

   2007    2006    2005    2004    2003

Balance Sheet data:

              

Current assets

   $ 5,051    $ 4,992    $ 4,637    $ 3,880    $ 4,524

Property, plant and equipment, net

     24,153      22,775      21,981      21,482      20,630

Noncurrent regulatory assets

     5,133      5,808      4,734      5,076      5,564

Goodwill (a)

     2,625      2,694      3,475      4,705      4,719

Other deferred debits and other assets

     8,932      8,050      7,970      7,867      6,800
                                  

Total assets

   $ 45,894    $ 44,319    $ 42,797    $ 43,010    $ 42,237
                                  

Current liabilities

   $ 5,995    $ 5,795    $ 6,563    $ 4,836    $ 5,683

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

     11,965      11,911      11,760      12,148      13,489

Noncurrent regulatory liabilities

     3,301      3,025      2,518      2,490      2,229

Other deferred credits and other liabilities

     14,409      13,494      12,743      13,918      12,246

Minority interest

     —        —        1      42      —  

Preferred securities of subsidiary

     87      87      87      87      87

Shareholders’ equity

     10,137      10,007      9,125      9,489      8,503
                                  

Total liabilities and shareholders’ equity

   $ 45,894    $ 44,319    $ 42,797    $ 43,010    $ 42,237
                                  

 

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the impact of the goodwill impairment charge of $776 million and $1.2 billion in 2006 and 2005, respectively.

 

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 Operation included in ITEM 7 of this Report on Form 10-K.

 

The results of operations for Generation’s retail business are not included in periods prior to 2004.

 

     For the Years Ended December 31,  

(in millions)

   2007    2006    2005     2004     2003  

Statement of Operations data:

            

Operating revenues

   $ 10,749    $ 9,143    $ 9,046     $ 7,703     $ 8,135  

Operating income (loss)

     3,392      2,396      1,852       1,039       (115 )

Income (loss) from continuing operations

   $ 2,025    $ 1,403    $ 1,109     $ 657     $ (241 )

Income (loss) from discontinued operations

     4      4      19       (16 )     —    

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

     2,029      1,407      1,128       641       (241 )

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

     —        —        (30 )     32       108  
                                      

Net income (loss) (a)

     $2,029      $1,407      $1,098       $673       $(133)  
                                      

 

(a) Change between 2004 and 2003 was primarily due to the impairment of Boston Generating, LLC long-lived assets of $945 million in 2003.

 

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     December 31,

(in millions)

   2007    2006    2005    2004    2003

Balance Sheet data:

              

Current assets

   $ 2,795    $ 3,433    $ 3,040    $ 2,321    $ 2,438

Property, plant and equipment, net

     8,043      7,514      7,464      7,536      7,106

Deferred debits and other assets

     8,216      7,962      7,220      6,581      5,105
                                  

Total assets

   $ 19,054    $ 18,909    $ 17,724    $ 16,438    $ 14,649
                                  

Current liabilities

   $ 2,446    $ 2,914    $ 3,400    $ 2,416    $ 3,553

Long-term debt

     2,513      1,778      1,788      2,583      1,649

Deferred credits and other liabilities

     9,725      8,733      8,554      8,356      6,488

Minority interest

     1      1      2      44      3

Member’s equity

     4,369      5,483      3,980      3,039      2,956
                                  

Total liabilities and member’s equity

   $ 19,054    $ 18,909    $ 17,724    $ 16,438    $ 14,649
                                  

 

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 Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,

(in millions)

   2007    2006     2005     2004    2003

Statement of Operations data:

            

Operating revenues

   $ 6,104    $ 6,101     $ 6,264     $ 5,803    $ 5,814

Operating income (loss)

     512      555       (12 )     1,617      1,567

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

   $ 165    $ (112 )   $ (676 )   $ 676    $ 702

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

     —        —         (9 )     —        5
                                    

Net income (loss) (a)

   $ 165    $ (112 )   $ (685 )   $ 676    $ 707
                                    

 

(a) The changes between 2007 and 2006; 2006 and 2005 and 2005 and 2004 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)

   2007    2006    2005    2004    2003

Balance Sheet data:

              

Current assets

   $ 1,241    $ 1,007    $ 1,024    $ 1,196    $ 1,313

Property, plant and equipment, net

     11,127      10,457      9,906      9,463      9,096

Goodwill (a)

     2,625      2,694      3,475      4,705      4,719

Noncurrent regulatory assets

     503      532      280      240      326

Other deferred debits and other assets

     3,880      3,084      2,806      2,077      2,837
                                  

Total assets

   $ 19,376    $ 17,774    $ 17,491    $ 17,681    $ 18,291
                                  

Current liabilities

   $ 1,712    $ 1,600    $ 2,308    $ 1,764    $ 1,557

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

     4,384      4,133      3,541      4,282      5,887

Noncurrent regulatory liabilities

     3,447      2,824      2,450      2,444      2,217

Other deferred credits and other liabilities

     3,305      2,919      2,796      2,451      2,288

Shareholders’ equity

     6,528      6,298      6,396      6,740      6,342
                                  

Total liabilities and shareholders’ equity

   $ 19,376    $ 17,774    $ 17,491    $ 17,681    $ 18,291
                                  

 

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(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

 

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 Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,

(in millions)

   2007    2006    2005     2004    2003

Statement of Operations data:

             

Operating revenues

   $ 5,613    $ 5,168    $ 4,910     $ 4,487    $ 4,388

Operating income

     947      866      1,049       1,014      1,056

Income before cumulative effect of a change in accounting principle

   $ 507    $ 441    $ 520     $ 455    $ 473

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

     —        —        (3 )     —        —  

Net income

   $ 507    $ 441    $ 517     $ 455    $ 473
                                   

Net income on common stock

   $ 503    $ 437    $ 513     $ 452    $ 468
                                   

 

     December 31,

(in millions)

   2007    2006    2005    2004    2003

Balance Sheet data:

              

Current assets

   $ 800    $ 762    $ 795    $ 727    $ 659

Property, plant and equipment, net

     4,842      4,651      4,471      4,329      4,256

Noncurrent regulatory assets

     3,273      3,896      4,454      4,836      5,238

Other deferred debits and other assets

     895      464      366      241      232
                                  

Total assets

   $ 9,810    $ 9,773    $ 10,086    $ 10,133    $ 10,385
                                  

Current liabilities

   $ 1,516    $ 978    $ 936    $ 748    $ 676

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

     2,866      3,784      4,143      4,628      5,239

Noncurrent regulatory liabilities

     250      151      68      46      12

Other deferred credits and other liabilities

     3,068      3,051      3,235      3,313      3,442

Shareholders’ equity

     2,110      1,809      1,704      1,398      1,016
                                  

Total liabilities and shareholders’ equity

   $ 9,810    $ 9,773    $ 10,086    $ 10,133    $ 10,385
                                  

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

 

Exelon

 

General

 

Exelon is a utility services holding company. It operates through subsidiaries in the following operating segments:

 

   

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 and wholesale sale of electricity and the provision of distribution and transmission services to retail customers 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 distribution and transmission 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.

 

See Note 21 of the Combined Notes to Consolidated Financial Statements for further segment information.

 

Exelon’s corporate operations, some of which are performed through its business services subsidiary, BSC, provide Exelon’s business segments 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 $2,736 million in 2007 as compared to $1,592 million in 2006 and diluted earnings per average common share were $4.05 for 2007 as compared to $2.35 for 2006. The increase in net income was primarily due to the following:

 

   

the impact of a $776 million impairment charge in 2006 associated with ComEd’s goodwill;

 

   

higher average margins on Generation’s wholesale market sales primarily due to the end of the below-market price PPA with ComEd at the end of 2006;

 

   

increased transmission revenues at ComEd;

 

   

increased rates for delivery services at ComEd;

 

   

favorable weather conditions in the ComEd and PECO service territories;

 

   

increased delivery volume, excluding the effects of weather, at ComEd and PECO;

 

   

income associated with the termination of Generation’s PPA with State Line Energy, L.L.C. (State Line);

 

   

gains realized on decommissioning trust fund investments related to changes in the investment strategy;

 

   

favorable income tax benefit associated with Exelon’s method of capitalizing overhead costs; and

 

   

the impact of a charge in 2006 associated with the termination of the proposed merger with PSEG.

 

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The factors driving the overall increase in net income were partially offset by the following:

 

   

decreased energy margins (operating revenues net of purchased power expense) at ComEd due to the end of the regulatory transition period;

 

   

increased mark-to-market losses on contracts not yet settled;

 

   

the impact of the Illinois Settlement Legislation described below;

 

   

increased nuclear decommissioning-related activity;

 

   

the impact of inflationary cost pressures;

 

   

increased amortization expense, primarily related to scheduled CTC amortization at PECO;

 

   

a charitable contribution of $50 million to the Exelon Foundation;

 

   

a charge associated with Generation’s tolling agreement with Georgia Power related to the contract with Tenaska Georgia Partners, LP (Tenaska); and

 

   

the impact of a benefit in 2006 of approximately $288 million to recover certain costs allowed by the Illinois Commerce Commission (ICC) rate orders.

 

Financing Activities. During 2007, Exelon met its capital resource requirements primarily with internally generated cash as well as funds from external sources, including the capital markets, and through bank borrowings. During 2007, Generation, ComEd and PECO issued $746 million, $725 million and $175 million, respectively, of long-term debt. In addition, during 2007, ComEd borrowed $370 million under its credit facilities and repaid all outstanding commercial paper. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information on the Registrants’ debt and credit facilities.

 

On September 4, 2007, Exelon entered into agreements with two investment banks to repurchase a total of $1.25 billion of Exelon’s common shares under an accelerated share repurchase arrangement. In September 2007, Exelon received 15.1 million shares in accordance with the accelerated share repurchase agreements, which were recorded as treasury stock, at cost, for $1.17 billion. On December 19, 2007, Exelon’s Board of Directors authorized a new share repurchase program of up to $500 million of Exelon’s outstanding common stock. This new program is in addition to the $1.25 billion share repurchase executed in September 2007. See Note 17 of the Combined Notes to Consolidated Financial Statements for further information.

 

On December 19, 2007, the Exelon Board of Directors declared a quarterly dividend of $0.50 per share on Exelon’s common stock. This dividend declaration was made by the Exelon Board of Directors under a value return policy that established a base dividend that Exelon expects will grow modestly over time.

 

The Registrants performed an assessment during the fourth quarter of 2007 to determine the impact, if any, of recent market developments, including a series of rating agency downgrades of subprime U.S. mortgage-related assets. The Registrants believe that the fair value of their investments, their ability to access liquidity in the market at reasonable rates, their ability to dispose of assets or liabilities as needed to meet financial obligations, and their counterparties’ creditworthiness will not be significantly affected by the subprime credit crisis.

 

Regulatory and Environmental Developments. The following significant regulatory and environmental developments occurred during 2007. See Notes 4 and 19 of the Combined Notes to Consolidated Financial Statements for further information.

 

   

Illinois Settlement Legislation and Related Proceedings—In July 2007, ComEd and Generation were party to an agreement (Settlement) that concluded discussions of measures to address

 

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concerns about higher electric bills in Illinois since the end of the rate freeze transition period on December 31, 2006. The Settlement did not include rate freeze, generation tax or other legislation that would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation implementing the settlement (Settlement Legislation) was signed into law in August 2007 by the Governor of Illinois.

 

       Under the Settlement Legislation, Illinois electric utilities, their affiliates, and generators of electricity in Illinois will make voluntary contributions of approximately $1 billion over a period of four years to programs that will provide rate relief to Illinois electricity customers and partial funding for the IPA. Generation and ComEd committed to contributing an aggregate of over $800 million to rate relief programs and funding for the IPA. ComEd continues to execute upon its $64 million rate relief package announced earlier in 2007 whereby contributions to rate relief programs of approximately $41 million were made in 2007. Generation will contribute an aggregate of $747 million, of which $435 million will be available to pay ComEd for rate relief programs for ComEd customers, and $307.5 million will be available for rate relief programs for customers of other Illinois utilities and $4.5 million will be available for partial funding of the IPA. ComEd, Generation, and the Attorney General of the State of Illinois (Illinois Attorney General) also entered into a release and settlement agreement releasing and dismissing with prejudice all litigation, claims and regulatory proceedings and appeals related to the procurement of power, including ICC and FERC proceedings. Additionally, in the event that legislation is enacted prior to August 1, 2011 that would freeze or reduce electric rates or impose a generation tax on any party to the Settlement, the Settlement provides for the contributors to the rate relief funds to terminate their funding commitments and recover any undisbursed funds set aside for rate relief.

 

       In addition to creating the IPA, the Settlement Legislation established a new competitive process that Illinois utilities will be required to use for the procurement of electricity supply resources and for the implementation of defined levels of cost-effective renewable energy resources. The IPA will participate in the design of electricity supply portfolios for ComEd and will administer the new competitive process to procure the electricity supply resources and renewable energy resources identified in the supply portfolio plans, all under the oversight of the ICC. This process will take place for all future delivery periods with the exception of the delivery period starting in June 2008 in which a ComEd-developed plan approved by the ICC would be administered. In October 2007, ComEd filed a petition with the ICC seeking approval of an initial procurement plan. The procurement plan and the spot market purchases discussed below will be used to secure power and other ancillary services for retail electric customers for the period June 2008 through May 2009. An ALJ issued a Proposed Order on December 11, 2007, approving virtually every aspect of the proposal. On December 19, 2007, the ICC approved the Proposed Order. In addition to the procurement plan, ComEd will purchase energy on the spot market to meet the needs of its customers. Additionally, to fulfill a requirement of the Settlement, ComEd and Generation entered into a five-year financial swap contract whereby ComEd will pay fixed prices and Generation will pay a market price for a portion of ComEd’s electricity supply requirement. This contract effectively hedges a significant portion of ComEd’s spot market purchases. The financial swap contract became effective upon the enactment of the Settlement Legislation. The Settlement Legislation deems this arrangement prudent and thereby ensures that ComEd will be entitled to receive full recovery of its costs in its rates.

 

      

The Settlement Legislation further requires that electric utilities use cost-effective energy efficiency and demand response resources to meet incremental annual goals. In November 2007, ComEd filed its initial Energy Efficiency and Demand Response Plan with the ICC and expects an ICC order to be issued on the filing during the first quarter of 2008. This plan begins on June 1, 2008 and is designed to meet the Settlement Legislation’s energy efficiency

 

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and demand response goals for an initial three-year period, including reductions in delivered energy and in ComEd’s supply customers’ peak demand. If targets are met, ComEd customers would reduce their electricity consumption by a cumulative amount of approximately 1.2 million MWh at the end of the three years. Savings on customers’ bills is expected to pay for the cost of implementing the programs and produce additional net savings of more than $155 million over the lifetime of the programs. Once implemented, the programs would place ComEd among the top three utilities in the nation in terms of annual electricity savings achieved through energy efficiency.

 

       The Settlement Legislation also declared that the 400 kW and above customer classes of ComEd are competitive. On October 11, 2007, the ICC granted a request made by ComEd by declaring that customer classes with demands of 100 kW or greater but less than 400 kW are competitive, effective on November 11, 2007. Consequently, after the expiration of a three-year transitional period, ComEd will have a POLR obligation only for those customers with demand of less than 100 kW who have not chosen a competitive electric generation supplier.

 

       Other provisions in the Settlement Legislation extend the ability of utilities to engage in divestiture and other restructuring transactions, after only having to make an informational filing at the ICC, and ensure that until at least June 30, 2022, the state will not prohibit an electric utility from maintaining its membership in a FERC-approved regional transmission organization chosen by the utility.

 

   

Illinois Procurement Proceedings—On March 28, 2007 and March 30, 2007, class action suits were filed in Illinois state court against ComEd and Generation as well as the other suppliers in the Illinois procurement auction that occurred in September 2006. The suits claimed that the suppliers manipulated the auction and that the resulting wholesale prices were unlawfully high. On December 21, 2007, a United States District Court granted the defendants’ motions to dismiss both cases and the time to appeal that order has expired.

 

   

Delivery Service Rate Case—On October 17, 2007, ComEd filed a request with the ICC seeking approval to increase its delivery service rates to reflect its continued investment in delivery service assets since rates were last determined. If approved by the ICC, the total proposed increase of approximately $360 million in the net annual revenue requirement, which was based on a 2006 test year, would increase an average residential customer bill by approximately 7.7%. ICC proceedings relating to the proposed delivery service rates will take place over a period of up to eleven months.

 

   

Transmission Rate Case—On March 1, 2007, ComEd filed a request with FERC, seeking approval to increase the rate ComEd receives for transmission services. ComEd also requested incentive rate treatment for certain transmission projects. On June 5, 2007, FERC issued an order that conditionally approved ComEd’s proposal to implement a formula-based transmission rate effective as of May 1, 2007, but subject to refund, hearing procedures and conditions. The order denied ComEd’s request for incentive rate treatment on investment in certain transmission projects and the inclusion of construction work in progress in rate base. On October 5, 2007, ComEd made a filing with FERC seeking approval of a settlement agreement reached on the case that had been announced by the settlement judge to FERC in September 2007. The settlement agreement is a comprehensive resolution of all issues in the proceeding, other than ComEd’s pending request for rehearing on incentive returns on new investment. The settlement agreement establishes the 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 and results in a first year annual transmission network service revenue requirement increase of approximately $93 million, or a $24 million reduction from the revenue requirement conditionally approved by FERC on June 5, 2007. FERC approved the settlement on January 16, 2008. Management believes that appropriate reserves

 

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have been established for transmission revenues that will be refunded in accordance with the final settlement agreement. On January 18, 2008, FERC issued an order on rehearing that allowed a 1.5% adder to return on equity for ComEd’s largest transmission project and authorized the inclusion of 100% of construction work in progress in rate base for that project but rejected incentive treatment for any other project ComEd has pending.

 

   

City of Chicago Settlement—On December 21, 2007, ComEd entered into a settlement agreement with the City of Chicago (City) regarding a wide range of issues including components of its franchise agreement with the City and other matters. Pursuant to the terms of the settlement agreement, ComEd will make payments totaling $55 million to the City through 2012 so long as the City meets specified conditions contained in the settlement agreement. The first payment of $23 million was made in December 2007. The City has agreed not to challenge ComEd’s position in certain regulatory proceedings during the term of the Settlement Agreement, including, among others, ComEd’s delivery service rate case, the recent transmission rate case, and ComEd’s proposed revenue requirements in future rate cases when increases in the revenue requirement do not exceed specified increases in the Consumer Price Index. The City further agreed to allow ComEd to cancel various projects previously required under the franchise agreement with the City and to defer completion of other required projects. The settlement agreement also settles other disputes between ComEd and the City, including dismissing the City’s appeal of ComEd’s 2005 delivery rate case. ComEd and the City also agreed to establish a panel of ComEd and City representatives to evaluate opportunities to improve service reliability in the City.

 

   

PECO AEPS Filing—On March 19, 2007, PECO filed a request with PAPUC for approval to acquire and bank up to 450,000 non-solar Tier I Alternative Energy Credits (equivalent to up to 240 MWs of electricity generated by wind) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance under the AEPS Act following the completion of its transition period. On July 16, 2007, the Pennsylvania legislature modified the previously proposed AEPS Act in HB 1203. The modification did not affect PECO’s request for acquiring and banking Alternative Energy Credits or the proposed deferral of related costs. The PAPUC approved PECO’s filing on December 20, 2007. Using an independent Request for Proposal (RFP) monitor, PECO will conduct an RFP process for alternative energy producers to submit bids to sell credits beginning in March 2008.

 

Outlook for 2008 and Beyond.

 

Exelon’s future financial results will be affected by a number of factors, including the following:

 

   

The Settlement Legislation is expected to provide ComEd with greater stability and certainty that it will be able to procure electricity and pass through the costs of that electricity to its customers with less risk that rate freeze or other harmful legislation will be pursued in the near term. The Settlement Legislation established a new competitive procurement model to be developed by the IPA, by which ComEd will procure its energy supply. ComEd has stabilized a portion of its costs of procurement pursuant to the five-year financial swap contract with Generation. ComEd will be allowed to fully recover the costs of procuring energy, including the impacts of the financial swap contract, in its rates. In the event that legislation is enacted in the Illinois General Assembly prior to August 1, 2011 that freezes or reduces electric rates or imposes a generation tax, the Settlement Legislation permits ComEd and Generation, as contributors to certain rate relief programs, to terminate their funding commitments to such programs and recover any undisbursed funds set aside for rate relief.

 

   

PECO was subject to electric rate caps on its transmission and distribution rates through December 31, 2006 and is subject to caps on its generation rates through December 31, 2010. PECO’s transmission and distribution rates will continue in effect until PECO files a rate case

 

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or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so. PECO is or will be involved in proceedings involving annual changes in its electric and gas universal service fund cost charges, its electric CTC/intangible transition charge reconciliation mechanism, its purchased gas cost rate, and its every five-year nuclear decommissioning cost adjustment clause mechanism, all of which relate to PECO’s recovery of the applicable costs.

 

   

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 2008 and 2009. 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 has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years as well.

 

   

Generation procures nuclear fuel assemblies through long-term contracts for uranium concentrates and through long-term contracts for conversion services, enrichment services and fuel fabrication services. Generation procures coal primarily through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. 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. 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 these commodity price exposures.

 

   

The PPA between Generation and PECO expires at the end of 2010. Current market prices for electricity have increased significantly over the past few years due to the rise in natural gas and other fuel prices. As a result, PECO customers’ generation rates are below current wholesale energy market prices and Generation’s margins on sales in excess of PECO’s requirements have improved historically. Generation’s ability to achieve those margins following the expiration of the PPA will partially depend on future wholesale market prices.

 

   

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 climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these plans become effective, Exelon may incur costs to either further limit the GHG emissions from its operations or in procuring emission allowance credits. However, Exelon may benefit from stricter emission standards due to its significant nuclear capacity, which is not anticipated to be adversely affected by the proposed emission standards. On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U. S. EPA holding that carbon dioxide and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule, and Federal or state legislation.

 

   

Exelon anticipates that it will be subject to the ongoing pressures of rising operating expenses due to increases in costs, such as medical benefits and rising payroll costs due to inflation.

 

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Also, Exelon will continue to incur significant capital costs associated with its commitment to produce and deliver energy reliably to its customers. Increasing capital costs may include the price of uranium, which fuels the nuclear facilities, and continued capital investment in Exelon’s aging distribution infrastructure and generating facilities. Exelon is determined to operate its businesses responsibly and to appropriately manage its operating and capital costs while serving its customers and producing value for its shareholders.

 

   

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. On September 29, 2006, Generation notified the NRC that Generation will begin the application process for a combined COL that would allow for the possible construction of a new nuclear plant in Texas. The filing of the letter with the NRC launched a process that preserves for Exelon and Generation the option to develop a new nuclear plant in Texas without immediately committing to the full project. In order to continue preserving and assessing this option, Exelon and Generation have approved expenditures on the project of up to $100 million, which includes fees and costs related to the COL, reservation payments and other costs for long-lead components of the project, and other site evaluation and development costs. The development phase of the project is expected to extend into 2009, and funding beyond the $100 million commitment would be subject to extensive analysis. Generation has not made a decision to build a new nuclear plant at this time. Among the various conditions that must be resolved before any formal decision to build is made are a workable solution to spent nuclear fuel disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using the new technology can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, production and other potential tax credits, and other key economic factors. Generation expects to submit the COL application to the NRC in 2008.

 

   

On December 11, 2007, Generation announced that it will seek to accelerate the decommissioning of its Zion Station in Illinois more than a decade earlier than originally planned. Generation has contracted with EnergySolutions, Inc. to dismantle the nuclear plant, which closed in 1998. Completion of the arrangement is subject to the satisfaction of a number of closing conditions, including the receipt of a private letter ruling from the Internal Revenue Service. Additionally, the NRC must approve the arrangement, and this decision is not expected before the second half of 2008. Upon approval, the Zion Station’s licenses and decommissioning funds would be transferred to EnergySolutions, Inc.

 

   

During 2006, FERC issued its order approving PJM’s settlement proposal related to its RPM to provide for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period. FERC’s adoption of the settlement proposal has had a favorable impact for owners of generation facilities, particularly for facilities located in constrained zones. PJM’s RPM auctions took place in April 2007, July 2007, October 2007 and January 2008 and established prices for the period from June 1, 2007 through May 31, 2011. Subsequent auctions will take place 36 months ahead of the scheduled delivery year.

 

   

On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in a challenge to the final Phase II rule implementing Section 316(b) of the Clean Water Act. By its action, the court invalidated compliance measures that the utility industry supported because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. The court’s opinion has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. Several industry parties to the litigation sought review by the entire U.S. Court of Appeals for the Second Circuit, which was denied on July 5, 2007. On November 2, 2007, the industry parties filed a petition seeking review by the U.S. Supreme Court. The respondent environmental and state parties have until March 1, 2008 to respond to the petition. On July 9, 2007, the EPA formally suspended the Phase II rule due to the uncertainty about the specific

 

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compliance requirements created by the Court’s remand of significant provisions of the rule. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures. Due to this uncertainty, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. If the final rule, or interim state requirements under best professional judgment, has performance standards that require the reduction of cooling water intake flow at the plants consistent with closed loop cooling systems, then the impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, financial position and cash flows could be material.

 

   

On May 10, 2007, after completion of a two-year rule making process, the PAPUC adopted final default service regulations, an accompanying policy statement, and a price mitigation policy statement. The regulations allow for competitive procurement by distribution companies through auctions or Requests for Proposals, with full cost recovery and no retrospective prudence review. According to the policy statement, the PAPUC expects companies to procure power, on a customer-class basis, using contracts of varying expiration dates, and prefers contracts with a duration of one year or less, except for contracts for compliance with the AEPS Act. The PAPUC also expects companies to reconcile costs and adjust rates at least quarterly for most customers, but hourly or monthly for larger energy users. The PAPUC believes this combination will stimulate competition, send market-price signals and avoid price spikes following long periods of fixed, capped rates. The PAPUC also ordered the elimination of (1) declining-block rates, while allowing rates to be phased out if the resulting rate increase is greater than 25%; and (2) demand charges for large customers, while entertaining requests to retain those charges on a case-by-case basis. Electric distribution companies, such as PECO, will be required to make their implementation filings a minimum of 12 months prior to the end of the generation rate cap period, which for PECO, expires December 31, 2010. The final default service regulations became effective on September 15, 2007.

 

   

In Pennsylvania and other states where rate cap transition periods have ended or are approaching expiration, there is growing pressure from state regulators and elected officials to mitigate the potential impact of electricity price increases on retail customers. Such transition periods have ended for six Pennsylvania electric distribution companies and, in some instances, post-transition electricity price increases occurred. In response to concerns about post-transition rate increases in Pennsylvania, several measures have been either proposed or contemplated by various stakeholders. Certain legislators, for example, have suggested an extension of rate caps. Other measures previously proposed by the Pennsylvania Governor as part of his Energy Independence Strategy included, among other things: a phase-in of increased generation rates after expiration of rate caps; installation of smart metering technology; permission for electric distribution companies to enter into long-term contracts with large industrial customers; creation of a fee on electric consumption that would help fund an $850 million Energy Independence Fund designed to spur the development of a biofuels industry in the state as well as to promote the advancement of energy efficiency and renewable energy initiatives; a requirement for electric distribution companies, such as PECO, to procure electricity for their default-service customers after the end of their electric restructuring period (post-2010 for PECO), through a least-cost portfolio approach, with preferences for conservation and renewable power and permit distribution companies to enter into long-term procurement contracts to enable the construction of new generation. As of February 7, 2008, no portion of the Governor’s environmental agenda has been enacted into law. PECO cannot predict what measures, if any, will be introduced in the state legislature or become law in Pennsylvania, nor the disposition of measures in the Pennsylvania Governor’s Energy Independence Strategy. However, any legislation that requires PECO to sell electricity,

 

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beginning in 2011, at prices that are below PECO’s cost to procure and deliver electricity to customers or other legislation that would freeze rates or extend the rate cap beyond 2010 could have a material adverse effect on Exelon’s and PECO’s results of operations and cash flows.

 

   

On October 15, 2007, Generation entered into an agreement (Termination Agreement) with State Line Energy, L.L.C. (State Line), an indirect wholly owned subsidiary of Dominion Resources Inc., to terminate the Power Purchase Agreement dated as of April 17, 1996 (as amended, the PPA) between State Line and Generation relating to the State Line generating facility in Hammond, Indiana. Under the PPA, Generation controlled 515 MW of electric energy and capacity from the State Line facility. FERC approved the Termination Agreement on October 18, 2007. Further, the conditions to the effectiveness of the Termination Agreement were subsequently satisfied and Generation received a net cash payment from State Line of approximately $228 million, after adjustments, in consideration for the termination of the PPA and for the purchase of coal inventories on hand (and in transit) and other assets. As a result of the Termination Agreement, a negative net income impact to Generation of approximately $30 million to $35 million (after tax) per year is expected beginning in 2008 through the end of the original contract term in 2012.

 

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. Further discussion of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

 

Nuclear Decommissioning Asset Retirement Obligations (ARO) (Exelon and Generation)

 

Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143).

 

SFAS No. 143 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 which 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 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 a minimum of 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

 

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factors and are based on inflation indices for labor, equipment and materials, energy, low-level radioactive waste 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 low-level radioactive waste 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 20-year delay) 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 spent nuclear fuel for permanent disposal.

 

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, 2007

Cost escalation studies

  

Uniform increase in escalation rates of 25 basis points

   $ 313

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

   $ 113

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

   $ 147

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

   $ 226

 

Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on a periodic basis due to the passage of time and revisions to either the timing or estimated amount of the future undiscounted cash flows required to decommission the nuclear plants. For more information regarding the application of SFAS No. 143, see Notes 1 and 13 of the Combined Notes to Consolidated Financial Statements.

 

Asset Impairments (Exelon, Generation, ComEd and PECO)

 

Goodwill (Exelon and ComEd)

 

Exelon and ComEd have goodwill which relates to the acquisition of ComEd under the PECO/Unicom Merger. Under the provisions of SFAS No. 142, Exelon and ComEd perform assessments for

 

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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 a reporting unit below its carrying amount. Application of the goodwill impairment test requires management judgment, including the identification of reporting units, assigning assets, liabilities and goodwill to reporting units, and determining the fair value of the reporting unit. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

 

In the assessment, Exelon and ComEd estimate the fair value of the ComEd reporting unit using a probability-weighted, discounted cash flow model with scenarios reflecting management’s plans and a resulting range of operating results and cash flows. The model includes an estimate of ComEd’s terminal value based on these expected cash flows and on an earnings multiple approach, which reflects the estimated value of comparable utility companies. Other significant assumptions used in estimating the fair value of the ComEd reporting unit include ComEd’s capital structure, interest rates, utility sector market performance, operating and capital expenditure requirements and other factors. Changes in these variables or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of approximately 13% in expected discounted cash flows in ComEd’s 2007 annual assessment would have resulted in ComEd and Exelon failing step 1 of the impairment test. ComEd and Exelon would be required to perform step 2 of the impairment test to determine the amount of an impairment, if any. An impairment would require Exelon and ComEd to reduce both goodwill and current period earnings by the amount of the impairment.

 

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. 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 would require the affected registrant to reduce both the long-lived asset and current period earnings by the amount of the impairment.

 

Investments (Exelon, Generation, ComEd and PECO)

 

Exelon, Generation, ComEd, and PECO had investments, including investments held in nuclear decommissioning trust funds, recorded as of December 31, 2007. Beginning in 2006, and in connection with the issuance of FASB Staff Position FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. Since the NRC sets limitations on Exelon’s and Generation’s ability to direct the management of the nuclear decommissioning trust fund investments, Exelon and Generation do not have the ability to hold investments with unrealized losses through a recovery period and, accordingly, unrealized holding losses are recognized immediately, which are included in other, net in Exelon’s and Generation’s Consolidated Statements of Operations.

 

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

 

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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. Changes to depreciation estimates in future periods could have a significant impact on the amount of property, plant and equipment recorded and the amount of depreciation expense recorded in the income statement.

 

The estimated service lives of the nuclear-fuel 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. A change in depreciation estimates resulting from Generation’s inability to receive additional license renewals could have a significant effect on Generation’s results of operations. Generation also periodically evaluates the estimated service lives of its fossil fuel and hydroelectric generating facilities based on feasibility assessments as well as economic and capital requirements. 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 reviews its estimated service lives when circumstances, such as technological changes, warrant such a review. ComEd’s last depreciation study was performed in 2002.

 

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. The impact of the new rates was not material.

 

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

 

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO, and Exelon Corporate employees, except for those employees of Generation’s wholly owned subsidiary, AmerGen, who participate in the separate AmerGen-sponsored defined benefit pension plan and other postretirement welfare benefit plan. See Note 15—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding the accounting for the defined benefit pension plans and postretirement benefit plans.

 

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, Exelon considers historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, 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, level of compensation and rate of compensation increases, employee age, length of service, the long-term expected investment crediting rate, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees.

 

The selection of key actuarial assumptions utilized in the measurement of the plan obligations and costs drives the results of the analysis and the resulting charges. The long-term expected rate of return on plan assets (EROA) assumption used in calculating pension cost was 8.75% for 2007 and 9.00% for 2006 and 2005. The weighted average EROA assumption used in calculating other postretirement

 

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benefit costs was 7.85%, 8.15% and 8.30% in 2007, 2006 and 2005, respectively. A lower EROA is used in the calculation of other postretirement benefit costs, as the other postretirement benefit trust activity is partially taxable while the pension trust activity is non-taxable. The EROA is based on current and forecasted asset allocations as described in Note 15—Retirement Benefits of the Combined Notes to Consolidated Financial Statements. A change in the strategy of the asset allocations could significantly impact the EROA and related costs.

 

Exelon calculates the expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) allow the MRV of plan assets to be 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. Exelon uses a calculated value when determining the MRV of the pension plan assets that adjusts for 20% of the difference between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which Exelon applies that expected return. Exelon uses fair value when determining the MRV of the other postretirement benefit plan assets and the AmerGen pension plan assets.

 

The discount rate for determining the pension benefit obligations was 6.20%, 5.90% and 5.60% at December 31, 2007, 2006 and 2005, respectively. The discount rate for determining the other postretirement benefit obligations was 6.20%, 5.85% and 5.60% at December 31, 2007, 2006 and 2005, respectively. At December 31, 2007, 2006 and 2005, the discount rate was determined by developing a spot rate curve based on the yield to maturity of more than 400 Aa graded 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.

 

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 and EROA of 6.20% and 8.75%, respectively, for estimating its 2008 pension costs. Additionally, Exelon will use a discount rate and expected return on plan assets of 6.20% and 7.80%, respectively, for estimating its 2008 other postretirement benefit costs.

 

The following tables illustrate the effects of changing certain of the major actuarial assumptions discussed above (dollars in millions):

 

Change in Actuarial Assumption

  Impact on
Pension Liability at
December 31, 2007
  Impact on
2007
Pension Cost
  Impact on
Postretirement
Benefit Liability at
December 31, 2007
  Impact on 2007
Postretirement
Benefit Cost

Pension benefits

       

Decrease discount rate by 0.5%

  $ 648   $ 57   $ 207   $ 26

Decrease rate of EROA by 0.5%

    —       47     —       7

 

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Assumed health care cost trend rates also have a significant effect on the costs reported for Exelon’s and AmerGen’s postretirement benefit plans. A one-percentage point change in assumed health care cost trend rates would have had the following effects on the December 31, 2007 postretirement benefit obligation and estimated 2007 costs (dollars in millions):

 

Change in Actuarial Assumption

   Impact on
Other
Postretirement
Benefit

Obligation at
December 31, 2007
    Impact on
2007
Total Service

and
Interest Cost
Components
 

Increase assumed health care cost trend by 1%

   $ 422     $ 48  

Decrease assumed health care cost trend by 1%

     (349 )     (39 )

 

Extending the year at which the ultimate health care trend rate of 5% is forecasted to be reached by 5 years would have had the following effects on the December 31, 2007 postretirement benefit obligation and estimated 2007 costs (dollars in millions):

 

Change in Actuarial Assumption

   Impact on
Other
Postretirement

Benefit
Obligation at
December 31, 2007
   Impact on
2007

Total Service
and

Interest Cost
Components

Increase the year at which the ultimate health care trend rate of 5% is forecasted to be reached by 5 years

   $ 139    $ 18

 

The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. As these assumptions change from period to period, recorded pension and postretirement benefit amounts and funding requirements could also change. The impact of assumption changes on pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the employees rather than immediately recognized in the income statement as allowed by SFAS No. 87 and SFAS No. 106.

 

For pension benefits, Exelon amortizes its unrecognized prior service costs, transition obligations, 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 participants’ average remaining service period to expected retirement. The average remaining service period of defined pension plan participants was 13.0 years, 13.5 years and 13.8 years for the years ended December 31, 2007, 2006 and 2005, respectively. The average remaining service period of postretirement benefit plan participants related to eligibility age was 6.9 years, 7.3 years and 7.5 years for the years ended December 31, 2007, 2006 and 2005, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.7 years, 10.3 years and 10.9 years for the years ended December 31, 2007, 2006 and 2005, respectively.

 

Regulatory Accounting (Exelon, ComEd and PECO)

 

Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with SFAS No. 71, 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 recovery through rates charged to customers. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or gains that are required to be returned to customers. Use of SFAS No. 71 is

 

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applicable to utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. As of December 31, 2007, 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 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 businesses, 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 SFAS No. 71 could be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2007, the extraordinary gain could have been as much as $2.9 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities had it been determined that ComEd could no longer maintain regulatory assets and liabilities under SFAS No. 71. Similarly, at December 31, 2007, the extraordinary charge could have been as much as $3.0 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities had it been determined that PECO could no longer maintain regulatory assets and liabilities under SFAS No. 71. 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 (before taxes) charge against other comprehensive income of up to $1.2 billion and $74 million for ComEd and PECO, respectively, related to Exelon’s regulatory assets associated with its defined benefit postretirement plans. The resolution of the above items and the impact on ComEd’s capital structure 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 write-off of regulatory assets and liabilities could limit the ability of ComEd and PECO to pay dividends under Federal and state law. See Notes 4, 8 and 20 of the Combined Notes to Consolidated Financial Statements for further 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 to 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 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 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 a five-year financial swap contract with Generation that extends into 2013. PECO has entered into derivative gas contracts

to hedge its long term price risk in the natural gas market. ComEd and PECO do not enter into

 

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derivatives for proprietary trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 10 of the Combined Notes to Consolidated Financial Statements for further information regarding the Registrants’ derivative instruments.

 

The Registrants account for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) and related interpretations. Determining whether or not a contract qualifies as a derivative under SFAS No. 133 requires that management exercise significant judgment, including assessing the liquidity of its market as well as determining whether a contract has one or more underlyings and one or more notional amounts. Further, interpretive guidance related to SFAS No. 133 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 interpretive guidance related to SFAS No. 133 could result in previously excluded contracts being subject to the provisions of SFAS No. 133. Generation has determined that contracts to purchase uranium do not meet the definition of a derivative under SFAS No. 133 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 the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or 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 cost or value 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. For ComEd’s financial swap contract with Generation, ComEd records changes in the fair value of the swap as well as an offsetting regulatory asset or liability.

 

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 or normal sales are recognized when the underlying physical transaction is completed. “Normal” purchases and sales are contracts where 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 SFAS No. 133, the majority of these transactions have been designated as “normal” purchases or “normal” sales and are thus not required to be recorded at fair value, but on an accrual basis of accounting. 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.

 

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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 SFAS No. 133, hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings.

 

As a result of the Settlement reached in 2007, ComEd and Generation entered into a financial swap contract that has been designated as a cash flow hedge by Generation but has not been designated for hedge accounting by ComEd. The effect of the contract will be to cause Generation to pay market prices and ComEd to pay fixed prices for a portion of ComEd’s electricity supply requirement into 2013. In Exelon’s consolidated financial statements, all financial statement effects of the swap recorded by Generation and ComEd are eliminated.

 

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. Generation uses quoted exchange prices to the extent they are available or external broker quotes in order to determine the fair value of energy contracts. When external prices are not available, Generation uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific market in which the energy is being purchased, using externally available forward market pricing curves for all periods possible under the pricing model. For options contracts, Generation uses the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market.

 

See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk—Normal Operations and Hedging Activities for further information regarding sensitivity analysis related to market price exposure.

 

Interest-Rate Derivative Instruments. To determine the fair value of interest-rate swap agreements, the Registrants primarily use available market pricing curves.

 

Taxation (Exelon, Generation, ComEd and PECO)

 

Beginning January 1, 2007, the Registrants began accounting 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 FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48). 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. Prior to January 1, 2007, the Registrants estimated their uncertain income tax obligations in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), SFAS No. 5, and Statement of Financial Accounting Concepts No. 6, “Elements of Financial Statements-a replacement of FASB Concepts Statement No. 3 (incorporating

 

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an amendment of FASB Concepts Statement No. 2)” (CON 6). The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or interest income in other income and deductions on their Consolidated Statements of Operations. The Registrants also have non-income tax obligations related to real estate, sales and use and employment-related taxes and ongoing appeals related to these tax matters that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and CON 6.

 

Accounting for tax positions requires judgments, including estimating reserves for potential uncertainties. 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 do not record valuation allowances for deferred tax assets that the Registrants believe will be realized in future periods. While the Registrants believe the resulting tax balances as of December 31, 2007 and 2006 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and CON 6 as applicable, 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 12 of the Combined Notes to Consolidated Financial Statements for further 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 estimated 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 the liabilities and expenses in their 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 flow.

 

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.

 

Exelon and Generation have a reserve for asbestos-related bodily injury claims for open claims presented to Generation as of December 31, 2007 and for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Exelon’s

 

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and Generation’s management each determined that it was not reasonable to estimate future asbestos-related personal injury claims beyond 2030 based on the historical claims data available and the significant amount of judgment required to estimate this liability. In calculating the future losses, management made various assumptions, including but not limited to, the overall number of future claims estimated through the use of actuarial models, Exelon’s estimated portion of future settlements and obligations, the distribution of exposure sites, the anticipated future mix of diseases that relate to asbestos exposure and the anticipated levels of awards made to plaintiffs. Exelon obtains periodic updates of the estimate of future losses. The amounts recorded by Generation for estimated future asbestos-related bodily injury claims are based upon historical experience and actuarial studies. 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 asbestos-related litigation and possible legislative measures in the United States, could cause the actual costs to be higher or lower than projected. These estimates for asbestos-related bodily injury cases and settlements are difficult to predict and may be influenced by many factors. Accordingly, these matters, if resolved in a manner different from the estimate, could have a material effect on Exelon’s or Generation’s results of operations, financial position and cash flow.

 

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.

 

Generation’s revenue from service agreements is dependent upon when the services are rendered. Service agreements representing a cost recovery arrangement are presented gross within revenues for the amounts due from the party receiving the service, and the costs associated with providing the service are presented within operating and maintenance expenses.

 

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, 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

 

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prices as well as changes in ICC and PAPUC regulations, respectively. Under Pennsylvania’s Competition Act, licensed entities, including competitive electric generation suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO’s retail electric service territory. Currently, there are no third parties providing billing of PECO’s charges to customers or advanced metering; however, if this occurs, PECO would need to make adjustments to the provision for uncollectible accounts for the ability of the third parties to collect such receivables from the customers.

 

ComEd’s and PECO’s allowance for uncollectible accounts expense increased by $25 million and $13 million, respectively, in 2007 as compared to 2006. These increases resulted from a change in collectibility assumptions in response to changes in the customer payment patterns, changes in customer prices, changes in termination practices and certain changes in business and economic conditions. To the extent that actual collectibility differs from management’s estimates by 5%, the after-tax impact would be higher or lower by an estimated $4 million, $2 million, $2 million and less than $1 million for Exelon, ComEd, PECO and Generation, respectively. See ITEM 15. Exhibits and Financial Statement Schedules—Schedule II—Valuation and Qualifying Accounts for the rollforwards of allowance for uncollectible accounts.

 

Results of Operations (Dollars in millions, except for per share data, unless otherwise noted)

 

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

 

Results of Operations—Exelon

 

     2007     2006     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 18,916     $ 15,655     $ 3,261  

Operating expenses

      

Purchased power and fuel

     7,642       5,232       (2,410 )

Operating and maintenance

     4,289       3,868       (421 )

Impairment of goodwill

     —         776       776  

Depreciation and amortization

     1,520       1,487       (33 )

Taxes other than income

     797       771       (26 )
                        

Total operating expenses

     14,248       12,134       (2,114 )
                        

Operating income

     4,668       3,521       1,147  

Other income and deductions

      

Interest expense

     (647 )     (616 )     (31 )

Interest expense to affiliates, net

     (203 )     (264 )     61  

Equity in losses of unconsolidated affiliates

     (106 )     (111 )     5  

Other, net

     460       266       194  
                        

Total other income and deductions

     (496 )     (725 )     229  
                        

Income from continuing operations before income taxes

     4,172       2,796       1,376  

Income taxes

     1,446       1,206       (240 )
                        

Income from continuing operations

     2,726       1,590       1,136  

Income from discontinued operations, net of income taxes

     10       2       8  
                        

Net income

   $ 2,736     $ 1,592     $ 1,144  
                        

Diluted earnings per share

   $ 4.05     $ 2.35     $ 1.70  

 

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Net Income. Exelon’s net income for 2007 increased due to the impact of a $776 million impairment charge in 2006 associated with ComEd’s goodwill; higher average margins on Generation’s wholesale market sales primarily due to the end of the below-market price PPA with ComEd at the end of 2006; increased nuclear output at Generation reflecting fewer outage days; increased transmission revenues at ComEd; increased rates for delivery services at ComEd; favorable weather conditions in the ComEd and PECO service territories; increased delivery volume, excluding the effects of weather, at ComEd and PECO; income associated with the termination of Generation’s PPA with State Line; a favorable PJM billing settlement with PPL; decreased nuclear refueling outage costs; incremental storm costs in 2006 associated with storm damage in the PECO service territory; gains realized on decommissioning trust fund investments related to changes in the investment strategy; favorable income tax benefit associated with Exelon’s method of capitalizing overhead costs; increased earnings associated with synthetic fuel-producing facilities; the reduction in the reserve related to the successful PURTA tax appeal at PECO; and a charge in 2006 associated with the termination of the proposed merger with PSEG. These increases were partially offset by decreased energy margins at ComEd due to the end of the regulatory transition period; unrealized mark-to-market losses on contracts not yet settled; the impact of the Settlement; a loss associated with Generation’s tolling agreement with Georgia Power related to the contract with Tenaska; a greater reduction in 2006 compared to 2007 in Generation’s nuclear decommissioning obligation related to the AmerGen nuclear plants; the impact of inflationary cost pressures; increased pension and non-pension postretirement benefits expense; increased uncollectible accounts expense at ComEd and PECO; incremental storm costs associated with storm damage in the ComEd service territory; a charitable contribution of $50 million to the Exelon Foundation; increased amortization expense related to scheduled CTC amortization at PECO; costs associated with the possible construction of a new nuclear plant in Texas; benefits in 2006 of approximately $288 million to recover certain costs by the ICC rate orders; and the impact of favorable tax settlements at PECO in 2006.

 

Operating Revenues. Operating revenues increased due to an increase in wholesale and retail electric sales at Generation resulting from higher volumes of generation sold to the market at higher prices as a result of the expiration of the ComEd PPA at the end of 2006; income associated with the termination of Generation’s PPA with State Line; the impact of rate changes and mix at ComEd due to the end of the rate freeze and the implementation of market-based rates for electricity; increased transmission revenues at ComEd resulting from the 2007 transmission rate case; increased rates for delivery services at ComEd; favorable weather conditions in the ComEd and PECO service territories; higher delivery volumes, excluding the effects of weather, at ComEd and PECO; and authorized electric generation rate increases under the 1998 restructuring agreement at PECO. These increases were partially offset by the impact of the Settlement; more non-residential customers at ComEd electing to purchase electricity from a competitive electric generation supplier; costs associated with ComEd’s settlement agreement with the City of Chicago; and the expiration of certain wholesale contracts at ComEd. See further analysis and discussion of operating revenues by segment below.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense increased due to higher market energy prices; unrealized mark-to-market losses on contracts not yet settled; a loss associated with Generation’s tolling agreement with Georgia Power related to a contract with Tenaska; higher prices for electricity purchased by ComEd; and favorable weather conditions in the ComEd and PECO service territories. Purchased power represented 20% of Generation’s total supply for 2007 and 2006. The increases in purchase power and fuel expense were partially offset by a favorable PJM billing settlement with PPL; more non-residential customers at ComEd electing to purchase electricity from a competitive electric generation supplier; and the expiration of certain wholesale contracts at ComEd. In 2007, as a result of the ICC-approved reverse-auction process, ComEd began procuring electricity, including ancillary services, under its supplier forward contracts from PJM-administered wholesale electricity markets. See further analysis and discussion of purchased power and fuel expense by segment below.

 

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Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to increased pension and non-pension postretirement benefits expense; the impact of inflationary cost pressures; a greater reduction in 2006 compared to 2007 in Generation’s nuclear decommissioning obligation related to the AmerGen nuclear plants; increased uncollectible accounts expense at ComEd and PECO; incremental storm costs associated with storm damage in the ComEd service territory; a charitable contribution of $50 million to the Exelon Foundation; new nuclear site development costs for the evaluation and development of a new nuclear generating facility in Texas; increased tax consulting fees; and benefits of $201 million recorded at ComEd in 2006 as a result of the 2006 ICC rate orders. These increases were partially offset by a decrease in nuclear refueling outage costs associated with the fewer planned refueling outage days during 2007 compared to 2006; incremental storm costs in 2006 associated with storm damage in the PECO service territory; and a charge recorded in 2006 of approximately $55 million for the write-off of capitalized costs associated with the now terminated proposed merger with PSEG. See further discussion of operating and maintenance expenses by segment below.

 

Impairment of Goodwill. During 2006, ComEd recorded a $776 million impairment charge associated with its goodwill primarily due to the impacts of the ICC’s July 2006 rate order.

 

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to scheduled CTC amortization at PECO and additional plant placed in service across Exelon. These increases were partially offset by lower amortization related to investments in synthetic fuel-producing facilities.

 

Taxes Other Than Income. Taxes other than income increased primarily due to an increase in utility taxes resulting from higher utility revenues at PECO and the impact of favorable tax settlements at PECO in 2006. These increases were partially offset by a reduction in the reserve related to the successful PURTA tax appeal at PECO.

 

Other Income and Deductions. The change in other income and deductions reflects interest income related to the favorable PJM billing settlement with PPL; a gain related to the sale of investments by Generation; income and gains associated with nuclear decommissioning trust funds, net of other than temporary impairments, primarily associated with changes in Generation’s investment strategy; benefits of $87 million recorded by ComEd in 2006 as a result of the 2006 ICC rate order; and earnings associated with investments in synthetic fuel-producing facilities.

 

Effective Income Tax Rate. The effective income tax rate was 34.7% for 2007 compared to 43.1% for 2006. The 2007 rate decreased, as compared with 2006, primarily due to ComEd’s non-deductible goodwill impairment charge in 2006 which increased the rate by 9.7% and a decrease of state tax expense in 2007 of 1.5% due to a tax restructuring to allow utilization of separate company losses for state income tax purposes, partially offset by a reduction in synthetic fuel credits of 1.7% in 2007 caused by an increase in the phase-out due to higher oil prices, and other changes amounting to 1.1%. See Note 12 of the Combined Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates and discussion on the investments in synthetic fuel-producing facilities.

 

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc (Sithe). In addition, Exelon has sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises). Accordingly, the results of operations and any gain or loss on the sale of these entities have been presented as discontinued operations within Exelon’s (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations.

 

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Results of Operations by Business Segment

 

The comparisons of 2007 and 2006 operating results and other statistical information set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

 

Net Income (Loss) from Continuing Operations by Business Segment

 

     2007    2006     Favorable
(unfavorable)
variance

Generation

   $ 2,025    $ 1,403     $ 622

ComEd

     165      (112 )     277

PECO

     507      441       66

Other (a)

     29      (142 )     171
                     

Total

   $ 2,726    $ 1,590     $ 1,136
                     

 

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

 

Net Income (Loss) by Business Segment

 

     2007    2006     Favorable
(unfavorable)
variance

Generation

   $ 2,029    $ 1,407     $ 622

ComEd

     165      (112 )     277

PECO

     507      441       66

Other (a)

     35      (144 )     179
                     

Total

   $ 2,736    $ 1,592     $ 1,144
                     

 

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

 

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Results of Operations—Generation

 

     2007     2006     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 10,749     $ 9,143     $ 1,606  

Operating expenses

      

Purchased power and fuel

     4,451       3,978       (473 )

Operating and maintenance

     2,454       2,305       (149 )

Depreciation and amortization

     267       279       12  

Taxes other than income

     185       185       —    
                        

Total operating expenses

     7,357       6,747       (610 )
                        

Operating income

     3,392       2,396       996  
                        

Other income and deductions

      

Interest expense

     (161 )     (159 )     (2 )

Equity in losses of unconsolidated affiliates

     1       (9 )     10  

Other, net

     155       41       114  
                        

Total other income and deductions

     (5 )     (127 )     122  
                        

Income from continuing operations before income taxes

     3,387       2,269       1,118  

Income taxes

     1,362       866       (496 )
                        

Income from continuing operations

     2,025       1,403       622  

Discontinued operations

      

Gain on disposal of discontinued operations

     4       4       —    
                        

Income from discontinued operations

     4       4       —    
                        

Net income

   $ 2,029     $ 1,407     $ 622  
                        

 

Net Income. Generation’s net income for 2007 compared to 2006 increased primarily due to higher revenue, net of purchased power and fuel expense, more than offsetting inflationary and other cost pressures, a greater reduction in 2006 compared to 2007 in the nuclear decommissioning obligation related to the AmerGen nuclear plants and costs associated with the new nuclear plant COL application. Generation’s revenue, net of purchased power and fuel expense, increased due to higher average margins primarily due to the end of the below-market price PPA with ComEd at the end of 2006, the contractual increase in the prices associated with Generation’s PPA with PECO, the termination of the State Line PPA and a favorable PJM billing settlement with PPL in 2007, partially offset by amounts incurred in conjunction with the Settlement, net mark-to-market losses on derivative activities and the execution of the Georgia Power PPA. In addition to these impacts, Generation’s net income for 2007 included (all after tax) gains of $38 million related to changes in Generation’s investment strategy with the decommissioning trust fund investments, a gain on the sale of investments of $11 million and earnings of $4 million associated with the settlement of a tax matter related to Generation’s previous investment in Sithe.

 

Operating Revenues. For 2007 and 2006, Generation’s revenues were as follows:

 

Revenue

   2007     2006    Variance     % Change  

Electric sales to affiliates

   $ 3,537     $ 4,674    $ (1,137 )   (24.3 )%

Wholesale and retail electric sales

     6,834       3,640      3,194     87.7 %
                         

Total energy sales revenue

     10,371       8,314      2,057     24.7 %
                         

Retail gas sales

     449       540      (91 )   (16.9 )%

Trading portfolio

     43       14      29     207.1 %

Other revenue (a)

     (114 )     275      (389 )   (141.4 )%
                         

Total revenue

   $ 10,749     $ 9,143    $ 1,606     17.6 %
                         

 

(a) Includes amounts incurred for the Settlement, income associated with the termination of the State Line PPA, revenues relating to fossil fuel sales and operating service agreements, and decommissioning revenue from PECO during 2007. Includes sales related to tolling agreements, fossil fuel sales and operating service agreements and decommissioning revenue from ComEd and PECO during 2006.

 

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Sales (in GWhs)

   2007    2006    Variance     % Change  

Electric sales to affiliates

   64,406    119,354    (54,948 )   (46.0 )%

Wholesale and retail electric sales

   125,244    71,326    53,918     75.6 %
                  

Total sales

   189,650    190,680    (1,030 )   (0.5 )%
                  

 

Trading volumes of 20,323 GWhs and 31,692 GWhs for 2007 and 2006, respectively, are not included in the table above.

 

Electric sales to affiliates. The changes in Generation’s electric sales to affiliates for 2007 compared to 2006 consisted of the following:

 

Electric sales to affiliates

   Price    Volume     Increase
(decrease)
 

ComEd

   $ 650    $ (2,035 )   $ (1,385 )

PECO

     169      79       248  
                       

Total

   $ 819    $ (1,956 )   $ (1,137 )
                       

 

In the ComEd territories, decreased volumes were the result of the expiration of Generation’s PPA with ComEd effective December 31, 2006. The decrease was partially offset by higher prices received by Generation following the expiration of the PPA, under which Generation was receiving below-market rates. With the expiration of the PPA, Generation is now receiving higher prices from ComEd under the forward supply contracts.

 

In the PECO territories, higher prices were the result of a scheduled electric generation rate increase that took effect January 1, 2007.

 

Wholesale and retail electric sales. The changes in Generation’s wholesale and retail electric sales for 2007 compared to 2006 consisted of the following:

 

     Increase
(decrease)

Volume

   $ 2,782

Price

     412
      

Increase in wholesale and retail electric sales

   $ 3,194
      

 

The increase in wholesale and retail electric sales was primarily the result of higher volumes of generation sold to the market as a result of the expiration of the ComEd PPA at the end of 2006.

 

Retail gas sales. Retail gas sales decreased $91 million for 2007 as compared to 2006, of which $53 million of the decrease was due to lower volumes as a result of lower demand and $38 million was due to lower realized prices.

 

Other revenues. The decrease in other revenues in 2007 compared to 2006 was primarily due to a $408 million decrease for amounts recorded related to the Settlement, a decrease of $86 million due to the cessation of a tolling agreement and a $66 million decrease related to the termination of decommissioning collections from ComEd in accordance with the terms and conditions of the ICC order which only permitted such collections through December 31, 2006, partially offset by income of $223 million related to the termination of the State Line PPA. Additionally, a $40 million decrease in other revenues was attributable to the sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP) on February 9, 2007 and the resulting absence of revenue thereafter.

 

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Purchased Power and Fuel Expense. Generation’s supply sources are summarized below:

 

Supply Source (in GWhs)

   2007    2006    Variance     % Change  

Nuclear generation (a)

   140,359    139,610    749     0.5 %

Purchases—non-trading portfolio

   38,021    38,297    (276 )   (0.7 )%

Fossil and hydroelectric generation

   11,270    12,773    (1,503 )   (11.8 )%
                  

Total supply

   189,650    190,680    (1,030 )   (0.5 )%
                  

 

(a) Represents Generation’s proportionate share of the output of its nuclear generating plants, including Salem, which is operated by PSEG Nuclear.

 

The following table presents changes in Generation’s purchased power and fuel expense for 2007 compared to 2006. Generation considers the aggregation of purchased power and fuel expense as a useful measure to analyze the profitability of electric operations between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, the aggregation of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information Generation provides elsewhere in this report.

 

(in millions)

   Price     Volume     Increase
(Decrease)
 

Purchased power costs (a)

   $ 236     $ (47 )   $ 189  

Generation costs (b)

     2       (5 )     (3 )

Fuel resale costs

     (56 )     (38 )     (94 )

Mark-to-market

     n.m.       n.m.       275  
            

Increase in purchased power and fuel expense

       $ 367  
            

 

(a) Excludes the net impact of $119 million loss recorded in 2007 associated with Generation’s tolling agreement with Georgia Power related to the contract with Tenaska.
(b) Excludes the net impact of a $13 million one-time settlement with the Department of Energy recorded in 2006 for uranium enrichment services.
n.m. Not meaningful

 

Purchased Power Costs. Purchased power cost includes all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation had lower purchased power volumes primarily due to lower volumes needed to supply ComEd as a result of the expiration of the PPA at December 31, 2006. Generation incurred overall higher prices for purchased power, partially offset by a decrease of $28 million due to the favorable PJM billing dispute settlement with PPL in 2007. See Note 13 of the Combined Notes to Consolidated Financial Statements.

 

Generation Costs. Generation costs include fuel cost for internally generated energy. Generation costs were relatively flat in 2007, as compared to 2006. The decrease in volume of $5 million was primarily due to lower fossil and hydroelectric generation, partially offset by higher nuclear generation.

 

Fuel Resale Costs. Fuel resale costs include retail gas purchases and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs for 2007 as compared to 2006 consisted of overall lower prices resulting in a decrease of $56 million. Additionally, a decrease of $38 million was the result of lower volumes caused by lower demand.

 

Mark-to-market. Mark-to-market losses on power derivative activities were $253 million in 2007 compared to gains of $180 million in 2006. Mark-to-market gains on fuel derivative activities were $81 million in 2007 compared to losses of $77 million in 2006.

 

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The following table presents average electric revenues, supply costs and margins per MWh of electricity sold during 2007, as compared to 2006. As denoted in the table, average electric margins are defined as average electric revenues less average electric supply costs. Generation considers average electric margins useful measures to analyze the change in profitability of electric operations between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information Generation provides elsewhere in this report.

 

($/MWh)

   2007    2006    % Change  

Average electric revenue

        

Electric sales to affiliates

   $ 54.90    $ 39.16    40.2 %

Wholesale and retail electric sales

     54.59      51.03    7.0 %

Total—excluding the trading portfolio

     54.70      43.60    25.5 %

Average electric supply cost (a)(b)—excluding the trading portfolio

   $ 20.44    $ 18.02    13.4 %

Average margin—excluding the trading portfolio

   $ 34.26    $ 25.58    33.9 %

 

(a) Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales.
(b) Excludes the net impact of the $119 million loss related to the execution of the Georgia Power PPA and costs related to the termination of the State Line PPA during the twelve months ended December 31, 2007.

 

The following table presents nuclear fleet operating data for 2007 as compared to 2006. As demonstrated in the table, nuclear fleet capacity factor is defined as the ratio of the actual output of a plant over a period of time and its output if the plant had operated at full capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one (1) MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet production between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

 

     2007     2006  

Nuclear fleet capacity factor (a)

     94.5 %     93.9 %

Nuclear fleet production cost per MWh (a)

   $ 14.46     $ 13.85  

 

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

 

The nuclear fleet capacity factor increased primarily due to fewer outage days during 2007 compared to 2006. For 2007 and 2006, refueling outage days totaled 195 and 237, respectively, and non-refueling outage days totaled 59 and 71, respectively. The higher number of net MWh’s generated and lower costs due to fewer planned refueling outage days were offset by higher costs for labor, nuclear fuel, NRC reactor fees, security costs and material condition work, resulting in an increase in the production cost per MWh for 2007 as compared to 2006.

 

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Operating and Maintenance Expense. The increase in operating and maintenance expense for 2007 compared to 2006 consisted of the following:

 

     Increase
(Decrease)
 

Payroll, pension and benefit costs

   $ 85  

New nuclear site development costs

     49  

Decommissioning-related activities

     40  

TEG and TEP related expenses

     (39 )

Nuclear refueling outage costs including the co-owned Salem plant

     (32 )

Contractor expenses

     24  

Corporate allocations

     14  

Other

     8  
        

Increase in operating and maintenance expense

   $ 149  
        

 

   

The $85 million increase in payroll, pension and benefit costs reflected the impact of inflation as well as an increase in various direct fringe costs.

 

   

The $49 million increase in new nuclear site development costs was due to costs incurred for the evaluation and development of a new nuclear generating facility in Texas, including fees and costs related to the COL, reservation payments for long-lead components of the project, and other site evaluation and development costs.

 

   

The $40 million increase in nuclear decommissioning-related activities was primarily associated with the recognition of a credit of $29 million, compared to a credit of $149 million recognized in 2006, representing reductions in the asset retirement obligation in excess of the asset retirement cost balance for the AmerGen units. Additionally, decommissioning-related activities decreased by $66 million resulting from the termination of revenue collections on December 31, 2006 from ComEd, which likewise no longer required an offset through operating and maintenance expense, and decreased by $14 million due to the offset of certain income-taxes associated with decommission-related activity.

 

   

The $39 million decrease in expenses related to TEG and TEP was due to the sale of the investment in 2007.

 

   

The $32 million decrease in nuclear refueling outage costs was associated with the fewer planned refueling outage days during 2007 compared to 2006.

 

   

The $24 million increase in contractor expense was primarily related to staff augmentation and maintenance work at the nuclear, fossil and hydroelectric plants.

 

   

The $14 million increase in corporate support service costs reflected an increase in a variety of BSC services allocated to Generation, including legal, human resources, financial, information technology and supply management services.

 

Depreciation and Amortization. The decrease in depreciation and amortization expense for 2007 compared to 2006 was primarily due to the reassessment of the useful lives, for accounting purposes, of several fossil facilities and the write-off of certain asset retirement costs in 2006.

 

Interest Expense. The increase in net interest expense for 2007 compared to 2006 was primarily attributable to an increase in interest expense related to a change in the estimate of the FIN 48 tax interest calculation and an increase in interest expense related to the bond issuance during the third quarter of 2007, partially offset by an interest payment accrued in 2006 for the settlement of a tax matter, a decline in the amount of commercial paper that was outstanding and an increase in average cash-on-hand balances during 2007 compared to 2006.

 

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Other, Net. The increase in other, net in 2007 compared to 2006 reflects a gain on sale of investments recognized in 2007 and income and gains associated with nuclear decommissioning trust funds, net of other than temporary impairments, primarily associated with changes in Generation’s investment strategy. Effective January 1, 2008, the utilization of the fair value option under SFAS No. 159 for nuclear decommissioning trust funds will allow Generation to recognize unrealized gains, which will be included in other, net in Generation’s Consolidated Statements of Operations. See Note 1 of the Combined Notes to Consolidated Financial Statements for additional information regarding the impact of adoption of SFAS No. 159.

 

Effective Income Tax Rate. The effective tax rate was 40.2% for 2007 compared to 38.2% for 2006. The increase in the effective tax rate was attributable to an increase in deferred tax expense associated with the generation portion of ComEd’s research and development settlement as well as ComEd’s and PECO’s application of the indirect cost capitalization method settlement guidelines recorded in the fourth quarter of 2007. In addition, realized gains recognized in the fourth quarter by the qualified nuclear decommissioning trusts also contributed to the increase in the effective tax rate. See Note 12 of the Combined Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

 

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Operations. Generation’s Consolidated Statement of Income for 2007 reflects a $4 million (after tax) gain on the disposal of discontinued operations related primarily to Sithe, resulting from a settlement agreement between a subsidiary of Sithe, the Pennsylvania Attorney General’s Office and the Pennsylvania Department of Revenue regarding a previously disputed tax position asserted for the 2000 tax year. Generation’s Consolidated Statement of Income and Comprehensive Income for 2006 reflects a $4 million (after tax) gain on disposal of discontinued operations. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

 

Results of Operations—ComEd

 

     2007     2006     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 6,104 &n