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, 2006

 

OR

 

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

 

Commission File
        Number

  

Name of Registrant; 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

(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  ¨    No  x

Commonwealth Edison Company

   Yes  x    No  ¨

PECO Energy Company

   Yes  ¨    No  x

 

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  x    No  ¨

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, 2006, was as follows:

 

Exelon Corporation Common Stock, without par value

   $38,019,493,399

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, 2007 was as follows:

 

Exelon Corporation Common Stock, without par value

   670,157,335

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

   15
  

PECO Energy Company

   15
  

Employees

   20
  

Environmental Regulation

   21
  

Managing the Risks in the Business

   27
  

Executive Officers of the Registrants

   31

ITEM 1A.

   RISK FACTORS    33
  

Exelon Corporation

   33
  

Exelon Generation Company, LLC

   35
  

Commonwealth Edison Company

   41
  

PECO Energy Company

   41

ITEM 1B.

   UNRESOLVED STAFF COMMENTS    51

ITEM 2.

   PROPERTIES    51
  

Exelon Generation Company, LLC

   51
  

Commonwealth Edison Company

   53
  

PECO Energy Company

   53

ITEM 3.

   LEGAL PROCEEDINGS    54

ITEM 4.

   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    54

PART II

     

ITEM 5.

  

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

   55

ITEM 6.

   SELECTED FINANCIAL DATA    57
  

Exelon Corporation

   57
  

Exelon Generation Company, LLC

   59
  

Commonwealth Edison Company

   60
  

PECO Energy Company

   61

ITEM 7.

  

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

   62
  

Exelon Corporation

   62
  

Exelon Generation Company, LLC

   143
  

Commonwealth Edison Company

   145
  

PECO Energy Company

   147

ITEM 7A.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   134
  

Exelon Corporation

   134
  

Exelon Generation Company, LLC

   144
  

Commonwealth Edison Company

   146
  

PECO Energy Company

   148

ITEM 8.

   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    149
  

Exelon Corporation

   149

 

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          Page No.
  

Exelon Generation Company, LLC

   152
  

Commonwealth Edison Company

   153
  

PECO Energy Company

   154
  

Combined Notes to Consolidated Financial Statements

   179
  

1. Significant Policies

   179
  

2. Acquisitions and Dispositions

   204
  

3. Discontinued Operations

   209
  

4. Regulatory Issues

   210
  

5. Accounts Receivable

   221
  

6. Property, Plant and Equipment

   222
  

7. Jointly Owned Electric Utility Plant

   224
  

8. Intangible Assets

   224
  

9. Fair Value of Financial Assets and Liabilities

   227
  

10. Severance Accounting

   238
  

11. Debt and Credit Agreements

   239
  

12. Income Taxes

   247
  

13. Asset Retirement Obligations

   254
  

14. Retirement Benefits

   263
  

15. Preferred Securities

   275
  

16. Common Stock

   276
  

17. Earnings Per Share

   278
  

18. Commitments and Contingencies

   278
  

19. Supplemental Financial Information

   297
  

20. Segment Information

   312
  

21. Related Party Transactions

   313
  

22. Quarterly Data

   322
  

23. Subsequent Events

   324

ITEM 9.

  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   325

ITEM 9A.

   CONTROLS AND PROCEDURES    325
  

Exelon Corporation

   325
  

Exelon Generation Company, LLC

   325
  

Commonwealth Edison Company

   325
  

PECO Energy Company

   325

ITEM 9B.

   OTHER INFORMATION    325

PART III

     

ITEM 10.

  

DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

   326
  

Exelon Corporation

   326
  

Exelon Generation Company, LLC

   326
  

Commonwealth Edison Company

   327
  

PECO Energy Company

   328

ITEM 11.

   EXECUTIVE COMPENSATION    329

ITEM 12.

  

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

   373

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

   376

ITEM 14.

   PRINCIPAL ACCOUNTING FEES AND SERVICES    376
  

Exelon Corporation

   376
  

Exelon Generation Company, LLC

   377
  

Commonwealth Edison Company

   377
  

PECO Energy Company

   377

 

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          Page No.

PART IV

     

ITEM 15.

   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES    379

SIGNATURES

   397
  

Exelon Corporation

   397
  

Exelon Generation Company, LLC

   398
  

Commonwealth Edison Company

   399
  

PECO Energy Company

   400

CERTIFICATION EXHIBITS

   401

 

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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 18 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 20 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 and wholesale 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 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.

 

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.

 

Termination of Proposed Merger with Public Service Enterprise Group Incorporated

 

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would have been

 

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merged with and into Exelon (Merger). On September 14, 2006, Exelon terminated the Merger Agreement as a result of the failure to receive timely approval of the Merger from the New Jersey Board of Public Utilities (NJBPU).

 

Federal and State Regulation

 

Exelon is 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). 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 electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). 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).

 

Exelon was a registered holding company and subject to a number of restrictions under the Public Utility Holding Company Act of 1935 (PUHCA) until the repeal of PUHCA, effective on February 8, 2006, pursuant to the Energy Policy Act of 2005 (Energy Policy Act). With the repeal of PUHCA, the restrictions are no longer applicable to Exelon, and the SEC’s financing jurisdiction under PUHCA for Generation’s financings and ComEd’s and PECO’s short-term financings transferred to FERC. Exelon’s financings are not subject to FERC jurisdiction.

 

Under the Energy Policy Act, FERC was granted additional jurisdiction for 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. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation, the repeal of PUHCA enhanced the authority of states to regulate Exelon and its utility subsidiaries.

 

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, 2006, Generation owned generation assets with an aggregate net capacity of 25,543 MWs, including 16,945 MWs of nuclear capacity. In addition, Generation controlled another 7,691 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, beginning in 2007, 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.

 

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The PPA between Generation and PECO expires at the end of 2010. Generation's PPA with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions in Illinois for the procurement of electricity. As a result of the expiration of the PPA with ComEd and the results of the auctions, beginning in 2007, Generation will sell more power through bilateral agreements with other new and existing counterparties. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Generating Resources

 

At December 31, 2006, the generating resources of Generation consisted of the following:

 

Type of Capacity

   MWs

Owned generation assets (a)

  

Nuclear

   16,945

Fossil

   6,992

Hydroelectric

   1,606
    

Owned generation assets

   25,543

Long-term contracts (b)

   7,691

TEG and TEP (c)

   230
    

Total generating resources

   33,464
    

(a) See “Fuel” for sources of fuels used in electric generation.
(b) Long-term contracts range in duration up to 25 years.
(c) At December 31, 2006, Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owned 49.5% interests in two facilities in Mexico, each with a capacity of 230 MWs. On February 9, 2007, Generation sold its ownership interests in TEG and TEP.

 

The owned generating resources of Generation are located in the Midwest region (approximately 45% of capacity), the Mid-Atlantic region (approximately 44% of capacity), the Southern region (approximately 9%), and the Northeast region (approximately 2% of capacity) of the United States. The generating capacity that Generation controls through long-term contracts is in the Midwest, Southeast and South Central regions.

 

Nuclear Facilities

 

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,945 MWs of capacity. Generation’s nuclear fleet plus its ownership interest in the Salem Generating Station (Salem), operated by PSEG Nuclear, LLC (PSEG Nuclear), generated 139,610 GWhs, or approximately 92% of Generation’s total output, for the year ended December 31, 2006. 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 PSEG. AmerGen Energy Company, LLC (AmerGen), 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).

 

Effective January 17, 2005, Generation began overseeing daily plant operations at Salem and Hope Creek nuclear generating stations through an Operating Services Contract (OSC) with PSEG Nuclear. Hope Creek is a nuclear generating station wholly owned by PSEG Nuclear. Under the OSC, PSEG Nuclear remains as the license holder with exclusive legal authority to operate and maintain the stations, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the stations. The initial two-year term of the OSC terminated

 

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on January 16, 2007. However, PSEG Nuclear has exercised its right to require Generation to continue services under the OSC for an additional two-year termination transition period. Under the OSC, PSEG Nuclear has a right to extend the termination transition period for an additional year and PSEG Nuclear has reserved its right to do so.

 

In 2006 and 2005, electric supply generated from the nuclear generating facilities was 73% and 71%, respectively, of Generation’s total electric supply which also includes MWs purchased for resale and fossil and hydroelectric generation. During 2006 and 2005, the nuclear generating facilities operated by Generation achieved a 93.9% and 93.5% 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 of operation of 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, 2006, 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 Dresden Unit 2, and one indicator for Byron Unit 2, both of which are still considered to be in an acceptable performance band within that indicator by the NRC.

 

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. The application for Oyster Creek’s license renewal was filed July 22, 2005, in compliance with this order. 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 current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations. In the first quarter of 2005, Generation applied the same depreciation estimated useful life assumption to its ownership share in the Salem Generating Station.

 

In 2004, Generation joined NuStart Energy Development, LLC (NuStart), a consortium of eleven 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, 2006, Generation’s investment in NuStart was $1 million.

 

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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.

 

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek, Dresden and Quad Cities, some SNF has been placed in dry cask storage facilities. Not all of Generation’s SNF storage pools 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, 2006, Generation had approximately 46,778 SNF assemblies (11,317 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. 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 (b)

   2006

Dresden

   Dry cask storage in operation

LaSalle

   2012

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

 

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(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.
(b) Clinton has currently lost full core discharge capability. A modification to the on-site storage pool is in progress to increase the amount of SNF that can be stored in the pool and is expected to be completed in late 2007. This will move the date for loss of full core reserve at Clinton out to approximately 2012.

 

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (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 SNF 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 of dry cask storage at other stations. 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 13 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 part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2006, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $950 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, 2006, was 5.108%. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains 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 temporary 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 anticipates the possibility of continuing difficulties in disposing of LLRW. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts.

 

The National Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all

 

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domestic utilities covered by this requirement was originally $150 million per year through 2006, of which Generation’s share was approximately $20 million per year. Payments are adjusted annually to reflect inflation. Generation paid $32 million in 2006 ($28 million net after considering amounts collected from co-owners of certain nuclear stations).

 

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 under the terms of the Energy Policy Act. As of December 31, 2006, the current 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 and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.

 

See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.

 

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 in accordance with NRC regulations. 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; however, these current amounts are not considered material compared to the total ARO.

 

Under an ICC order, ComEd was permitted to recover up to $73 million per year through 2006 from customers to decommission former ComEd nuclear plants. Collections were limited based on the ratio of electricity purchased by ComEd to the total amount generated from those units. In 2006, decommissioning revenues collected from ComEd customers totaled approximately $66 million. Under the current ICC order, 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. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PAPUC. The amounts recovered are premised on studies that assume level contributions through the license expiration date for each unit. After completion of the decommissioning, any 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.

 

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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. 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.

 

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.

 

Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. The present value of Generation’s liability to decommission Zion, Peach Bottom Unit 1 and Dresden Unit 1 was $795 million at December 31, 2006. As of December 31, 2006, nuclear decommissioning trust funds set aside to pay for this obligation were $1.2 billion.

 

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 2006 and 2005, approximately 8% of Generation’s electric supply was generated from Generation’s owned fossil and hydroelectric generating facilities. 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 September 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 PJM Interconnection, LLC (PJM) or the New England control area administered by ISO New England Inc. (ISO-NE), notice is required 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 long-term contracts described below:

 

Seller

   Location    Expiration    Capacity (MWs)

Kincaid Generation, LLC

   Kincaid, Illinois    2011    1,108

Tenaska Georgia Partners, LP

   Franklin, Georgia    2030    925

Tenaska Frontier, Ltd

   Shiro, Texas    2020    830

Green Country Energy, LLC

   Jenks, Oklahoma    2022    795

Elwood Energy, LLC

   Elwood, Illinois    2012    772

Lincoln Generating Facility, LLC

   Manhattan, Illinois    2011    664

Reliant Energy Aurora, LP

   Aurora, Illinois    2008    600

Others (a)

   Various    2008 to 2023    1,997
          

Total

         7,691
          

(a) Includes long-term capacity contracts with seven counterparties.

 

Federal Power Act

 

The Federal Power Act gives FERC exclusive rate-making 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 access to transmission lines that enable it to participate in competitive wholesale markets.

 

Because Generation sells power in the wholesale markets, Generation is a public utility for purposes of the Federal Power Act and is required to obtain FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from FERC to sell power at market-based rates. As is customary with market-based rate schedules, FERC reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determined that Generation or any of its affiliates 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 new market power tests for suppliers to qualify to sell power at market-based rates. These tests consist of the market share test and the pivotal supplier test, both of which must be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market-based rates. FERC allows the relevant geographic market to include a regional transmission organization’s (RTOs) footprint, and Generation used an expanded PJM footprint as the relevant market.

 

On July 5, 2005, FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, FERC required Generation to address the affiliate abuse and reciprocal dealing prong of FERC’s market-based rate eligibility test, instituting a proceeding under Section 206 of the Federal Power Act, and pending a compliance filing by Generation. On April 3, 2006, FERC accepted Exelon’s compliance filings regarding its triennial update of market-based rates and terminated proceedings under Section 206 of the Federal Power Act. For further discussion of this matter, see Note 4 of the Combined Notes to Consolidated Financial Statements.

 

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For a number of years, FERC has been encouraging the voluntary formation of RTOs, such as PJM, 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 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.

 

FERC issued a final rule establishing standardized generator interconnection policies and procedures. Under this interconnection policy generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of various transmission providers.

 

The Energy Policy Act of 2005. The 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 generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. 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 creates a self-regulating electric reliability organization with FERC oversight to enforce reliability rules. On July 20, 2006, pursuant to the Energy Policy Act, FERC certified the North American Electric Reliability Corporation (NERC) as the nation’s Electric Reliability Organization. As a result, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, will be subject to mandatory reliability standards promulgated by NERC and enforced by FERC.

 

See Note 4 of the Combined Notes to Consolidated Financial Statements for further information on the Energy Policy Act of 2005 and its impact on the Registrants.

 

Market-Based Rates Matters

 

Currently, Exelon’s entities have been approved by FERC to sell power at market-based rates. On May 19, 2006, FERC issued a Notice of Proposed Rule Making (NOPR) on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, which would modify the tests that Exelon and other market participants must satisfy to be entitled to sell at market-based rates. Exelon currently expects that FERC will rule on the NOPR in the first or second quarter of 2007 and Exelon is not certain as to the impact of any new rules that are promulgated as a result of FERC’s future ruling with respect to the NOPR. Also, triggered by the expiration of the full-requirements PPA between Generation and ComEd and the resulting increase in Generation’s uncommitted capacity, on December 15, 2006, Exelon made a Change in Status (CIS) filing with

 

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FERC. Exelon’s filing, supported by an updated market-power analysis, demonstrated that Exelon continues to be entitled to market-based rates. The time period for interventions expired on January 5, 2007, no party intervened, and on February 9, 2007, FERC accepted Exelon’s CIS filing. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information on Market-Based Rates Matters and its impact on the Registrants.

 

PJM Reliability Pricing Model (RPM)

 

On August 31, 2005, PJM filed its RPM with FERC to replace its current capacity market rules. The RPM proposal provided for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. On November 5, 2005, PJM proposed to delay the effective date of the RPM until June 1, 2007. On April 20, 2006, FERC issued an order generally finding aspects of PJM’s RPM filing to be just and reasonable, but FERC also established further procedures to resolve the remaining issues and encouraged the parties to seek a negotiated resolution. A final settlement was filed with FERC on September 29, 2006 and FERC issued its order approving the settlement, subject to conditions, on December 22, 2006. FERC’s adoption of the settlement proposal of September 2006 is expected to have a favorable impact for owners of generation facilities, and particularly for such facilities located in constrained zones. The final revenue impact of the settlement on Generation, particularly over an extended time period, however cannot be estimated at this time.

 

FERC has also denied requests for rehearing of its April 20, 2006 order. The time for filing a petition for review of FERC’s April 2006 order will expire on February 20, 2007. In addition, FERC’s order approving the settlement subject to conditions is subject to requests for rehearing and judicial review. PJM will almost certainly implement RPM in 2007 notwithstanding, as FERC’s orders are rarely stayed, and therefore almost always remain in effect, pending appellate review. The first auction, which is scheduled to occur in April 2007, will allow Generation to better estimate the revenue impact for the period June 1, 2007 through May 31, 2008.

 

Fuel

 

The following table shows sources of electric supply in gigawatthours (GWhs) for 2006 and estimated for 2007:

 

     Source of Electric Supply
       2006        2007 (Est.)  

Nuclear units (a)

   139,610    139,752

Purchases—non-trading portfolio

   38,297    29,766

Fossil and hydroelectric units

   12,773    15,285
         

Total supply

   190,680    184,803
         

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

 

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 to ComEd and PECO, some of Generation’s retail business requirements, and for sales to other utilities.

 

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

 

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requirements through 2009. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2010. All of Generation’s enrichment requirements have been contracted through 2010. Contracts for fuel fabrication have been obtained through 2008. 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. alleging dumping in the United States against European enrichment services suppliers. 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 obtained for coal-fired plants primarily through annual contracts with the remainder supplied through either short-term contracts or spot-market purchases.

 

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

 

Generation uses financial instruments to mitigate price risk associated with 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 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 three years. Generation has estimated a greater than 90% economic and cash flow hedge ratio for

 

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2007 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, 2006, 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
Sales
   Power Only Purchases
from Non-Affiliates
   Transmission Rights
Purchases (b)

2007

   $ 468    $ 5,401    $ 1,499    $ 6

2008

     425      1,900      475      —  

2009

     398      647      194      —  

2010

     417      100      194      —  

2011

     417      —        106      —  

Thereafter

     2,960      —        249      —  
                           

Total

   $ 5,085    $ 8,048    $ 2,717    $ 6
                           

(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, 2006. Expected payments include certain capacity charges which are conditional on plant availability.
(b) Transmission rights purchases include estimated commitments in 2007 for additional transmission rights that will be required to fulfill firm sales contracts.

 

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy varied depending upon the time of day and month of delivery. Beginning January 2007, ComEd is procuring all of its supply from market sources pursuant to the ICC-approved procurement auction, which includes 35% from Generation. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail on the impact of ComEd’s procurement process on Generation. 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 2007 are as follows:

 

(in millions)

    

Production plant

   $ 754

Nuclear fuel

     599
      

Total

   $ 1,353
      

 

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ComEd and PECO

 

Exelon’s regulated energy delivery operations consist of ComEd and PECO.

 

ComEd is engaged principally in the purchase and regulated retail and wholesale sale of electricity and the provision of distribution and transmission services to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd is subject to extensive 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.

 

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 2007 to 2061. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

 

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 extensive 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 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.

 

PECO has the necessary authorizations to furnish regulated electric and 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.” These rights are generally unlimited as to time and are generally exclusive from competition from other electric and gas utilities. In a few defined municipalities, PECO’s gas service territory authorizations overlap with that of another gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

 

ComEd’s and 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. 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. 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.

 

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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 and in Illinois in December 1997. Both Illinois and Pennsylvania permit 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 in both states 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 recover a portion of the costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period.

 

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers, except for certain large customers of ComEd, 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 provider of last resort (POLR) obligations.

 

ComEd. As more fully described below, ComEd’s transition period has ended and new unbundled rates for service became effective January 2007. All of ComEd’s customers are eligible to choose a competitive electric generation supplier, and most non-residential customers also have a power purchase option (PPO) that is based on market-based rates. As of December 31, 2006, one competitive electric generation supplier had been granted approval by the ICC to serve residential customers in Illinois; however, it is not 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 rates, including the PPO option, that are based on a reverse-auction process. At December 31, 2006, approximately 20,300 non-residential customers, representing approximately 28% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier or had chosen the PPO. Customers who receive electricity from a competitive electric generation supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd.

 

Illinois Procurement Case and Initial ComEd Auction. On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of electricity by ComEd after the end of the transition period. This approval, currently under appeal before the Illinois Appellate Court, should provide ComEd with stability and greater certainty that it will be able to procure energy through the auction process and pass through the costs of that energy to ComEd’s customers through a transparent market mechanism. The first procurement auction for ComEd’s entire load took place during September 2006, for electricity to be delivered beginning in January 2007. Auction participants bid on several different products including 17-, 29- and 41-month contracts that will be “blended” together and used to serve residential and small commercial customers, a 17-month “annual” product that will be used to serve larger non-residential customers, and a variably priced “hourly” product that would be used to serve customers who either select hourly service or are not eligible to receive fixed price service. The ICC accepted the auction results related to the blended and annual products but rejected the auction results for the hourly product. Under ComEd’s tariffs, electricity that would have been procured through the hourly auction is currently being purchased in the PJM-administered wholesale electricity markets. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Rate Freeze Extension Proposal. In 2006 and 2007, various bills, amendments and “compromise” legislation were separately passed by the Illinois House and the Illinois Senate in a legislative session

 

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that ended on January 9, 2007, including, in the Illinois House, an extension of the Illinois transition period rate freeze with a rollback of rates to 2006 levels. However in order to take effect, any legislation would need to be passed by both the Illinois House and Illinois Senate and be signed by the Governor of Illinois. The legislative session ended on January 9, 2007 without any legislation having passed both the Illinois House and the Illinois Senate. All legislation pending at the close of the legislative session on January 9, 2007 expired. A new session is underway and legislation similar to previously proposed legislation has been reintroduced. ComEd is unable to predict the final disposition of any legislation that may be presented during 2007 to rollback rates, change the end of the mandated transition and rate freeze period in Illinois, or otherwise. ComEd believes a rate rollback and freeze, if enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. ComEd believes such legislation, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such legislation in court. If legislation similar to the “compromise” bill previously passed by the Illinois Senate to phase-in the rate increases is enacted, there would be material adverse effects on Exelon’s and ComEd’s results of operations and cash flows as the “compromise” bill did not provide for the recovery of carrying charges. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Illinois Rate Case. On August 31, 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 (Rate Case). On July 26, 2006, the ICC issued its order in the Rate Case which approved 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. On December 20, 2006, the ICC issued an order on rehearing that increased the amount previously approved by approximately $74 million, including a partial return on the pension asset, for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. It is unlikely the appeal will be resolved until the second half of 2007 at the earliest. In the event the order is ultimately changed, the changes should be prospective only. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Residential Rate Stabilization Program. To mitigate the impact on its residential customers of ComEd’s transition to a reverse-auction competitive bidding process for the procurement of electricity, the ICC approved a program, proposed by ComEd, which offers residential customers the choice to elect to defer electric rate increases greater than 10% in each of the years from 2007 to 2009. ComEd will recover the deferred balances over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25%. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Original Cost Audit. In the Rate Case, the ICC, ordered an “original cost” audit of ComEd’s distribution assets. The original cost audit report is expected to be finalized in 2007 with an ICC proceeding to follow the issuance of the report. This proceeding may extend into 2008. 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 2006, 2005 and 2004, ComEd did not have any outages that triggered the reimbursement requirement.

 

PECO. 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, 2006, less than 1% of each of PECO’s residential and large commercial

 

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and industrial loads and 10% 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 to PECO.

 

In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation, transmission and distribution rates. The 1998 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 settlement, PECO’s 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, were capped through December 31, 2010. For 2006, the generation rate cap was $0.0751 per kWh, increasing to $0.0801 per kWh in 2007. 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 capped transmission and distribution rates continue in effect until PECO 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 transition charges on customers’ bills. Transition charges 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 transition charges 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, 2006, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was $3.0 billion. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2007 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 transition charges 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 transition charges in any one year differ from the authorized amount set forth below, an annual reconciliation adjustment to the transition charge 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

2007

   $ 910    $ 619

2008

     917      697

2009

     924      783

2010

     932      883

 

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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 settlement of its restructuring case mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

 

Regulations applicable to all Pennsylvania electric utilities’ POLR obligations are being developed by the PAPUC. PECO and Generation will continue to monitor the developments of these regulations.

 

In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004. For more information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” below.

 

Transmission Services

 

ComEd and PECO provide wholesale and 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 facilities under filed tariffs at cost-based rates. Under FERC’s Order No. 889, 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 transmission 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 Interchange Energy Market and Capacity Credit 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 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. 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. An administrative law judge (ALJ) order related to this process was issued on July 13, 2006, which, if adopted by FERC, would result in a change to the existing rate design. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Gas

 

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

 

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quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates. PECO’s gas distribution base rates for recovery of costs other than purchased 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 gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 35% 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. 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 three years. These purchases are delivered under long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 42 million dekatherms. Peak gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 22 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 33% of PECO’s 2006-2007 heating season planned supplies.

 

Construction Budget

 

ComEd’s and PECO’s businesses are capital intensive and require significant investments primarily in energy transmission and distribution facilities. The following table shows the most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2007:

 

(in millions)

   ComEd    PECO

Electric

   $ 1,055    $ 269

Gas

     —        65

Common

     —        21
             

Total

   $ 1,055    $ 355
             

 

Approximately 50% of the projected 2007 capital expenditures at ComEd and PECO are for continuing efforts to maintain and improve the reliability of their transmission and distribution systems. The remainder of the capital expenditures support customer and load growth.

 

Employees

 

As of December 31, 2006, Exelon and its subsidiaries had approximately 17,200 employees in the following companies:

 

Generation

   7,700

ComEd

   5,500

PECO

   2,100

Other (a)

   1,900
    

Total

   17,200
    

(a) Other includes shared services employees at Exelon Business Services Company (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

 

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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 700 employees. The Generation CBA with IBEW Local 15 has been extended to September 30, 2007. 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 140 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, respectively. Exelon Power, an operating unit of Generation, has an agreement with Utility Workers of America Local 369, covering approximately 40 employees, which was ratified effective January 31, 2007 and which continues from year to year unless either party expresses its intention to terminate the agreement. In addition, Exelon Power has an agreement with IBEW Local 614, which expires on January 31, 2008 and covers approximately 200 employees.

 

During 2004, two elections were held at PECO, which resulted in union representation for PECO craft and call center employees in the Philadelphia service territory. PECO and IBEW Local 614 began negotiations for initial agreements in 2005. Although substantial progress has been made, no agreements have been finalized to date. The negotiations continue with the possibility of a tentative agreement being reached by the end of the first quarter in 2007. The current affected workgroup totals approximately 1,200 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 Exelon operates its 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 establishes national performance standards for reducing entrainment and impingement of aquatic organisms at existing power plants. On January 25, 2007, the U.S. Second Circuit Court of Appeals 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 rule the EPA either

 

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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 rule back to the EPA for revisions 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. See Note 18 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 violation 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, a class action lawsuit and several individual lawsuits were filed on behalf of persons living within the vicinity of the Braidwood Nuclear Generating Station. As of December 31, 2006 and 2005, Generation had a reserve of $3 million and $7 million (pre-tax), respectively, for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

 

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 18 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, however, 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. See Note 18 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. See Note 18 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 Pennsylvania, Massachusetts, Illinois and Texas in accordance with the Federal Clean Air Act and the Clean Air Act (CAA) 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. In addition, Generation and the other Keystone co-owners purchase SO2 emission allowances as part of their compliance strategy to meet Phase II limits.

 

Generation has completed implementation of measures, including the installation of NOx emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations and state-level ozone season (May to September) NOx reduction regulations. These state-level regulations were developed by eastern states to reduce summertime NOx emissions pursuant to several Federal NOx reduction regulations (“NOx SIP Call” regulations) adopted by the EPA during 1998 and 1999 to address regional “ozone transport.” State level NOx reduction regulations took effect May 1, 2003 in Pennsylvania and Massachusetts. Compliance in Illinois started May 31, 2004. Texas is not covered by the EPA’s NOx SIP Call regulations. The EPA’s NOx SIP Call regulations currently require 19 eastern states to reduce summertime NOx emissions.

 

Generation has evaluated options for compliance with the NOx SIP Call regulations and installed controls on the two coal-fired units at the Eddystone Generating Station and the coal-fired unit at Cromby (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units at the

 

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Keystone Generating Station (Selective Catalytic Reduction). Generation’s NOx compliance program is supplemented with the purchase of additional NOx allowances on an as-needed basis. The eight peaking units commissioned during 2002 at the Southeast Chicago Generating Station are equipped with NOx controls that meet requirements for new sources. The Handley and Mountain Creek stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NOx State Implementation Plan (SIP) that commenced on May 1, 2003, and that was fully implemented on May 1, 2005. Additionally, beginning May 1, 2003, these plants were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas for the purpose of achieving substantial reductions in NOx from grandfathered electric generating facilities. To comply with both the DFW NOx SIP and EBTA program, Generation installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Units 6 and 7.

 

During March 2005, the EPA finalized several new rulemakings designed to reduce powerplant 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. 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 that are currently under development, as well as the resolution of legal challenges initiated by certain parties (not including Exelon) in the Federal courts regarding the final CAIR and CAMR regulations. Legal challenges to a related final rulemaking, also published in March 2005, in which the EPA rescinded its December 2000 regulatory finding on hazardous air pollutants from electric utility steam generating units, may also have an effect on Generation’s final compliance decisions to the extent such litigation has an effect on the CAMR. During late 2005, the EPA agreed to reconsider and take additional public comment regarding certain aspects of its final CAIR and CAMR rulemakings. In March 2006, EPA determined that it would uphold its final CAIR rulemaking without change. In May 2006, EPA determined that, except for a number of minor technical revisions, it would maintain the CAMR as previously finalized.

 

During 2006, Pennsylvania proposed a state-level mercury regulation that is more stringent than the Federal CAMR. This rulemaking was finalized in October 2006 and submitted to the EPA in November 2006. 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 proposed 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.

 

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.

 

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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.

 

Global Climate Change

 

The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. 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 carbon dioxide (CO2) emissions, one of the greenhouse gases, released a program proposal. The RGGI Memorandum of Understanding (MOU) is an agreement to stabilize aggregate carbon dioxide 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 emissions. As of December 31, 2006, states participating in the RGGI MOU include Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont. Maryland, which had been an observer to the process, has also committed to join RGGI based on state legislation passed in 2006. On August 15, 2006, the RGGI model rule was finalized. RGGI member states will now be required to adopt state-level legislation and/or regulation to implement the program starting in 2009. Massachusetts has also recently joined RGGI as a result of legislation passed effective January 18, 2007. Further, the RGGI states will continue to work on some as yet unresolved issues, such as how to address emissions leakage due to power flows from non-RGGI states into RGGI states. Generation owns a small amount of affected generating capacity in the RGGI region. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

 

As an integrated electric and gas utility, approximately 90% of Exelon’s GHG emissions result from Generation’s combustion of fossil fuels to generate electricity, with CO2 representing the largest quantity of GHG emitted. The majority of Generation’s owned generation is comprised of nuclear and hydroelectric assets that have negligible GHG emissions compared to fossil-based electric generation alternatives. By virtue of Generation’s significant investment in these low-carbon intensity assets, Generation’s owned-generation portfolio CO2 emission intensity, or rate of CO2 emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.

 

Exelon announced on May 6, 2005 that it has established a voluntary goal to reduce its greenhouse gas (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 climate-reducing activities. Exelon made this pledge under the U.S. Environmental Protection Agency’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. Exelon believes that its planned greenhouse gas management efforts, including increased use of renewable energy, its current energy efficiency initiatives and its efforts in the areas of carbon sequestration, will allow it to achieve this goal. The anticipated cost of achieving the voluntary GHG emissions reduction goal will not have a material effect on Exelon’s future results of operations, financial condition or cash flows.

 

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Renewable and Alternative Energy Portfolio Standards

 

Approximately 26 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (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 begins 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 (starting at 0.0013% in year 1 and escalating to 0.25% by year 10). 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 cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is required. PECO’s cost recovery period expires December 31, 2010.

 

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.

 

During 2006, the PAPUC issued additional implementation orders and proposed regulations related to compliance schedules, banking of alternative energy credits, compliance, cost recovery, force majeure, alternative compliance payments and voluntary alternative energy purchases. It is anticipated that, during 2007, the PAPUC will finalize regulations concerning AEPS implementation issues.

 

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 influence on regional energy markets and, at the same time, may present some opportunities for sales of renewable power.

 

The ICC, in a January 24, 2006 order, ordered its staff to initiate three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources. On October 12, 2006, the ICC voted 5 to 0 to dismiss the three rulemaking proceedings. Separately on April 4, 2006, ComEd filed with the ICC a request for ICC approval to purchase and receive recovery of costs associated with the output of a portfolio of competitively procured wind resources of approximately 300 MW. ComEd asked, and the ALJ agreed, to continue these proceedings until

 

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February 2007. In the ICC’s December 20, 2006 order approving ComEd’s residential rate stabilization program, the ICC also strongly encouraged, but did not require, ComEd to make contributions totaling $30 million to environmental and customer assistance programs. ComEd is currently evaluating this request. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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. Exelon is currently evaluating the potential impacts of RPS legislation on its businesses.

 

Costs of Environmental Remediation

 

At December 31, 2006, Exelon, Generation, ComEd and PECO had accrued $119 million, $20 million, $58 million and $41 million, respectively, for various environmental investigation and remediation. Exelon, ComEd and PECO have recorded regulatory assets of $73 million, $47 million and $26 million, respectively, related to the recovery of MGP remediation costs. See Notes 18 and 19 of the Combined Notes to Consolidated Financial Statements for further detail.

 

The amounts to be expended in 2007 at Exelon, Generation, ComEd and PECO for compliance with environmental requirements total approximately $41 million, $17 million, $15 million and $9 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

 

Costs to meet contractual commitments. 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 stable fuel costs, minimal environmental impact from operations and a safe operating history.

 

Refueling outages. 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.

 

Operating services arrangement. Effective in 2005, as a result of the OSC with PSEG Nuclear, Generation is providing services to oversee daily plant operations at the Salem and Hope Creek nuclear generating stations. Under the OSC, PSEG Nuclear remains as the license holder with exclusive legal authority to operate and maintain the stations, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. As a result of the OSC, Generation has decreased certain exposures and increased revenues from its share of Salem, which it co-owns with PSEG Nuclear. The initial two-year term of the OSC

 

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terminated on January 16, 2007. However, PSEG Nuclear has exercised its right to require Generation to continue services under the OSC for an additional two-year termination transition period. Under the OSC, PSEG Nuclear has a right to extend the termination transition period for an additional year and PSEG Nuclear has reserved its right to do so.

 

Adequacy of funds to decommission nuclear power plants. Generation has an obligation to decommission its nuclear power plants. 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. The collections by PECO are based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than AmerGen facilities. The ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output of certain generating stations taken by ComEd, up to $73 million in both 2006 and 2005. Because ComEd did not take all of the output of these stations, actual collections were $66 million and $68 million in 2006 and 2005, respectively. PECO is currently recovering $33 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 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 compared to the total ARO. 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 $6.4 billion of investments in trust funds at December 31, 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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 a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large 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. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. Generation’s sales to counterparties other than ComEd and PECO will increase due to the expiration of the PPA with ComEd at the end of 2006. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings between ComEd and Generation and between Ameren and Generation will be one-sided. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren are not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation is required to post collateral.

 

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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 trading 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 2007 and 2008. 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 has estimated a greater than 90% economic and cash flow hedge ratio for 2007 for its energy marketing portfolio.

 

The PPA between Generation and PECO expires at the end of 2010. Market prices for electricity have generally increased significantly over the past few years due to the rise in natural gas and 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 ComEd’s and PECO’s requirements have improved due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants.

 

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

 

ComEd and PECO

 

Post-transition rates. In 2006, ComEd received orders from the ICC in several regulatory proceedings to establish the rates to be charged to customers effective January 2007. The first order relates to ComEd’s ability to procure electricity supply. The second order and the associated order on rehearing established the delivery service rates that will be charged to customers. Appeals are pending related to each order. A third order allows ComEd’s residential customers to have the choice to elect to defer any electric rate increases over 10% in each of the years 2007 to 2009. Any deferred balances will accrue interest and, in general, will be collected in 2010 to 2012 with a carrying charge of 3.25% per year beginning at the time of deferral.

 

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.

 

Mandatory RPS. ComEd expects to recover from customers any increased costs associated with RPS legislation if enacted. PECO is responsible for meeting its RPS requirements and, in that regard, plans to file with the PAPUC in the first quarter of 2007 a proposal to purchase renewable energy credits commencing as early as 2008. PECO expects to recover from customers all costs associated with RPSs. The Registrants are currently evaluating the potential impacts of RPS legislation on their businesses.

 

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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 as a result of its reverse-auction competitive bidding process. 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 effectively manage its obligation to provide power to meet its customers’ demand, PECO has a full-requirements PPA with Generation which 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 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.

 

Potential phase-out of tax credits. Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits in the event crude oil prices for a year exceed certain thresholds. See the risk factor “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” in ITEM 1A. Risk Factors for further detail. In 2005, Exelon and Generation entered into certain derivatives to economically hedge a portion of the oil price exposure related to the phase-out of tax credits. These derivatives could result in after-tax cash proceeds to Exelon of up to $42 million in 2007 in the event the tax credits are completely phased out. Additionally, under current laws, the tax credits related to the production of synthetic fuel expire on December 31, 2007. See Note 12 of the Combined Notes to Consolidated Financial Statements for further detail.

 

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.

 

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Executive Officers of the Registrants

 

Exelon

 

Name

   Age   

Position

Rowe, John W.

   61    Chairman, Chief Executive Officer and President

Clark, Frank M.

   61    Chairman and Chief Executive Officer, ComEd

McLean, Ian P.

   57    Executive Vice President and President, Power Team

Mehrberg, Randall E.

   51    Executive Vice President, Chief Administrative Officer and Chief Legal Officer

Moler, Elizabeth A.

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

Skolds, John L.

   56    Executive Vice President, Exelon, President, Exelon Energy Delivery and President, Exelon Generation

Snodgrass, S. Gary

   55    Executive Vice President and Chief Human Resources Officer

Young, John F.

   50    Executive Vice President, Finance and Markets and Chief Financial Officer

Hilzinger, Matthew F.

   43    Senior Vice President and Corporate Controller

 

Generation

 

Name

   Age   

Position

Rowe, John W.

   61    Chairman, Chief Executive Officer and President, Exelon

Young, John F.

   50    Executive Vice President, Finance and Markets and Chief
      Financial Officer, Exelon, and Chief Financial Officer

Skolds, John L.

   56    Executive Vice President, Exelon, and President

McLean, Ian P.

   57    Executive Vice President, Exelon, and President, Power Team

Crane, Christopher M.

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

Schiavoni, Mark A.

   51    Senior Vice President and President, Exelon Power

Veurink, Jon D.

   42    Vice President and Controller

 

ComEd

 

Name

   Age   

Position

Clark, Frank M.

   61    Chairman and Chief Executive Officer

Mitchell, J. Barry

   59    President

Costello, John T.

   58    Executive Vice President and Chief Operating Officer

McDonald, Robert K.

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

Pramaggiore, Anne R.

   48    Senior Vice President, Regulatory and External Affairs

Hooker, John T.

   58    Senior Vice President, Legislative and Governmental Affairs

Galvanoni, Matthew R.

   34    Vice President and Controller

 

PECO

 

Name

   Age   

Position

Rowe, John W.

   61    Chairman, Chief Executive Officer and President, Exelon, and Director

Young, John F.

   50    Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer

Skolds, John L.

   56    Executive Vice President, Exelon, President, Exelon Energy Delivery, and Director

O’Brien, Denis P.

   46    President and Director

Crutchfield, Lisa

   43    Senior Vice President, Regulatory and External Affairs

Galvanoni, Matthew R.

   34    Vice President and Controller

 

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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 President and Co-Chief Executive of Exelon, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; and Chairman, President and Chief Executive Officer of ComEd and Unicom. Mr. Rowe was elected as an officer of Exelon effective October 20, 2000.

 

Prior to his election to his listed positions, Mr. Clark was Executive Vice President and Chief of Staff of Exelon and President of ComEd; Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager. Mr. Clark was elected Chairman and Chief Executive Officer of ComEd effective November 28, 2005. Mr. Clark is listed as an executive officer of Exelon by reason of his position as the Chairman and Chief Executive Officer of ComEd.

 

Prior to his election to his listed position, Mr. McLean was Senior Vice President of Exelon; and President of the Power Team division of PECO. Mr. McLean was elected as an officer of Exelon effective October 20, 2000.

 

Prior to his election to his listed position, Mr. Mehrberg was Senior Vice President of Exelon. Mr. Mehrberg was elected as an officer of Exelon effective December 3, 2001.

 

Prior to her election to her listed position, Ms. Moler was Senior Vice President, Government Affairs and Policy of Exelon; Senior Vice President of ComEd and Unicom; and Director of Unicom and ComEd. Ms. Moler was elected as an officer of Exelon effective October 20, 2000.

 

Prior to his election to his listed positions, Mr. Skolds was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear. Mr. Skolds was elected as an officer of Exelon effective October 20, 2000.

 

Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation. Mr. Snodgrass was elected as an officer of Exelon effective October 20, 2000.

 

Prior to his election to his listed positions, Mr. Young was President of Exelon Generation; President of Exelon Power; Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation. Mr. Young was elected as an officer effective March 3, 2003.

 

Prior to his election to his listed position, Mr. Hilzinger was Executive Vice President and Chief Financial Officer of Credit Acceptance Corporation; and Vice President, Controller of Kmart Corporation. Mr. Hilzinger was elected as an officer of Exelon effective April 15, 2002. Mr. Hilzinger was Principal Accounting Officer for ComEd and PECO through December 31, 2006.

 

Prior to his election to his listed position, Mr. Crane was Vice President for Exelon Nuclear; and Vice President for BWR Operations of ComEd. Mr. Crane was elected as an officer of Generation effective December 27, 2000.

 

Prior to his election to his listed position, Mr. Schiavoni was Vice President of Operations; and Vice President of Northeast Operations of Exelon Power. Mr. Schiavoni was elected as an officer of Generation effective September 8, 2003.

 

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Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP. Mr. Veurink was elected as an officer of Generation effective January 5, 2004.

 

Prior to his election to his listed position, Mr. Mitchell was Senior Vice President, Chief Financial Officer and Treasurer of Exelon, Generation, ComEd and PECO; Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO. Mr. Mitchell was elected as President of ComEd effective November 28, 2005.

 

Prior to his election to his listed position, Mr. Costello was Senior Vice President of Exelon Energy Delivery Technical Services. Mr. Costello was Senior Vice President of Exelon Energy Delivery Customer and Marketing Services; and Vice President, Customer Operations. Mr. Costello was elected to his listed position with ComEd effective November 28, 2005.

 

Prior to his election to his listed position, Mr. McDonald was Senior Vice President of Planning and Chief Risk Officer of Exelon. Mr. McDonald has also served as Chief Risk Officer of Exelon, Vice President of Planning of Exelon and Vice President of Risk Management of Exelon. He was elected to his listed position with ComEd effective November 28, 2005.

 

Prior to her election to her listed position, Ms. Pramaggiore was Vice President, Regulatory and Strategic Services of ComEd. She has also served as Lead Counsel of ComEd. Ms. Pramaggiore was elected to her listed position with ComEd effective November 28, 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. Mr. Hooker has also served as Vice President Exelon Energy Delivery Property Management and ComEd Legislative and External Affairs; Vice President Distribution Services and Public Affairs; and Vice President of Governmental Affairs.

 

Prior to his election to his listed position, Mr. O’Brien was Executive Vice President of PECO; Vice President of Operations of PECO; Director of Transmission and Substations of PECO; and Director of BucksMont Region of PECO. Mr. O’Brien was elected as an officer of PECO effective January 1, 2001.

 

Prior to his election to his listed positions, Mr. Galvanoni was Director of Financial Reporting and Analysis, Exelon. Mr. Galvanoni has also served as Director of Accounting and Reporting, Generation; Director of Reporting, Exelon; and was a senior manager at PricewaterhouseCoopers LLP. Mr. Galvanoni was elected to his listed positions effective January 1, 2007.

 

Prior to her election to her listed position, Ms. Crutchfield served as Vice President, Regulatory and External Affairs, PECO; and Vice President and General Manager at Southern Service Center. Ms. Crutchfield was elected to her listed position effective January 1, 2007.

 

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 Board of Directors. The following items identify the material risks that the Registrants’ management discussed in December 2006.

 

    The safe and efficient operation of Generation’s nuclear fleet is a significant factor in Exelon’s results of operations. Although Generation’s nuclear plants are among the most efficient in the United States, there is a risk that Generation’s nuclear capacity factors could be significantly lower than planned or operating or fuel costs could be significantly higher than expected.

 

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After 2006 in Illinois, Generation has been selling, and after 2010 in Pennsylvania, Generation will be selling more of its electricity through bilateral agreements with new and existing counterparties at prices susceptible to market fluctuations. As a result, over time Exelon will shift from a company with relatively stable cash flows from its regulated affiliates to a company with cash flows that could vary significantly with changes in market prices for electricity and natural gas.

 

   

Prior to 2007, Generation supplied electricity to ComEd at prices that were below market prices. Generation supplies electricity to PECO at prices that are currently below prevailing market prices under a PPA that expires at the end of 2010. ComEd’s customers are experiencing increases in their costs for electric service beginning in 2007, and PECO’s customers could expect to see increases in their electric bills after 2010. In Illinois, Pennsylvania and other states, there is growing pressure on state regulators and governments to take steps to reduce the impact of price increases on retail customers. A move away from fully competitive generation markets as a result of regulatory or statutory requirements could significantly affect Exelon’s and Generation’s results of operations.

 

   

ComEd’s and PECO’s business plans are based on the assumption that the utilities will receive fair regulatory treatment and therefore, based on current Federal and state regulatory structures, can recover from customers revenue sufficient to cover their costs and earn a fair return. ComEd and PECO face the risk that rates for electric service will be set at levels that do not cover their costs of the purchase and distribution of electricity plus a fair return on their investments in transmission and distribution systems.

 

   

Generation attempts to reduce its exposure to energy market price fluctuations through derivative transactions. Hedging increases liquidity requirements due to margining requirements. Generation’s current PPA with PECO does not include a margin requirement. Beginning in 2007, Generation’s forward supply contracts with ComEd and third parties in Illinois do include margin requirements. Beginning in 2011, Generation’s contracts for supply of electricity to PECO may also include margin requirements. Generation will need to maintain expanded credit facilities to meet these margin requirements.

 

   

Exelon and Generation maintain and manage trust funds to meet future employee pension, postretirement and nuclear decommissioning costs. The fund investments are market instruments that will yield uncertain returns. There is a risk that the fund investments may not achieve projected returns, which could adversely affect Exelon’s and Generation’s results of operations and cash flows.

 

   

Active employee and retiree health care and pension cost are a significant part of Exelon’s cost structure. The costs associated with health care or pension obligations could escalate at rates higher than anticipated, which would adversely affect Exelon’s results of operations and cash flows.

 

   

The nature of the Registrants’ businesses has the potential to have significant effects on the general public due to severe weather, environmental or nuclear incidents, gas explosions, or prolonged electricity outages. The financial impact of an incident that interrupts the normal operation of a Registrant’s business for an extended period of time could be significant.

 

   

Exelon is subject to extensive environmental regulation and associated compliance costs. Regulations under section 316(b) of the Federal Clean Water Act require actions to address the entrainment and impingement of aquatic organisms in the cooling water intakes of electric generation facilities. A number of Generation’s facilities will be affected by these regulations, which could impose significant compliance costs on Generation for required modifications of its facilities.

 

The risks listed above are discussed in further detail below, along with other risk factors identified by the Registrants. These risk factors, as well as the risks discussed in ITEM 7. Management’s

 

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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.

 

Generation

 

Market Transition Risks

 

Due to its dependence on two of its 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 a PPA with PECO and supplier forward contracts with ComEd to meet 100% of PECO’s electricity supply requirements and up to 35% of ComEd’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.

 

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

 

Regional Transmission Organizations. 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, to meet long-term obligations not provided by its own resources and to take advantage of price opportunities.

 

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 79% 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, however, 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) with respect to PJM, the absence of material changes to market structure that limit or otherwise negatively affect the competitiveness of the market.

 

Provider of Last Resort. PECO and ComEd have POLR obligations to meet their respective retail customers’ energy supply needs. To enable it to fulfill that obligation through the end of 2010, PECO has a full-requirements PPA with Generation. To fulfill its obligation for energy supply beginning in 2007, ComEd has and will in the future conduct procurement auctions. In the first ICC-approved procurement auction, 14 wholesale suppliers, including Generation, won the right to provide to ComEd the energy supply it needs to serve its retail customers from January 1, 2007 through May 31, 2008. Generation’s share of this supply is 35%.

 

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 PECO’s obligation to supply PECO with all of the energy PECO needs to fulfill its POLR obligation and to provide the supply needed to serve Generation’s 35% 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

 

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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 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 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 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. These new generating facilities may be more efficient than Generation’s facilities. 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. Both Illinois and Pennsylvania statutes contemplate that future generation will be built in those markets at the risk of market participants. Construction of new generating facilities by Generation in markets in which it currently competes would be subject to market concentration tests administered by FERC. If Generation cannot pass these tests administered by FERC, it could be limited in how it responds to increased demand for energy.

 

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 its fossil or hydroelectric 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. 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 11 in 2006 with 9 planned for 2007. The projected total non-fuel capital expenditures for the nuclear plants operated by Generation will increase

 

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in 2007 compared to 2006 by approximately $37 million as Generation continues to invest in equipment upgrades to ensure safe reliable operations. Total operating and maintenance expenditures are expected to increase by approximately $52 million in 2007 compared to 2006 as a result of inflationary cost increases.

 

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 and/or increased outage costs. 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. Also, 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. In addition, 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.

 

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 and accelerated future decommissioning costs.

 

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.

 

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 renew the operating license.

 

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

 

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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.

 

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.

 

Nuclear Electric Insurance Limited (NEIL), a mutual insurance company to which Generation belongs, 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 2006 was $44 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 (NRC Funding Levels) including scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2006, Generation identified trust funds for 6 units, which, at current market levels, are being funded at a rate less than anticipated with respect to NRC Funding Levels. In December 2006, Generation made a submission to the NRC addressing this issue, demonstrating in accordance with NRC requirements, that the trust funds for these 6 units indeed met NRC Funding Levels and remain adequately funded compared to the NRC Funding Level, when using alternate evaluation criteria allowed by NRC regulations. The NRC Funding Levels are based upon the assumption that decommissioning will commence at 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

 

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 portfolio is used to provide power under a long-term PPA with PECO and supplier forward contracts with ComEd beginning January 2007, as a result of the expiration of the PPA between Generation and ComEd at the end of 2006. To the extent portions of the

 

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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 relies on the availability of electric transmission facilities that it does not own or control to deliver its wholesale electric power to the purchasers of the power, which may adversely affect its ability to deliver power to its customers.

 

Generation depends on transmission facilities owned and operated by other companies, including ComEd and PECO, to deliver the power that it sells at wholesale. If transmission at these facilities is disrupted or transmission capacity is inadequate, Generation may not be able to sell and deliver its wholesale power. The North American transmission grid is highly interconnected and, in extraordinary circumstances, disruptions at a point within the grid can cause a systemic response that results in an extensive power outage. If a region's power transmission infrastructure is inadequate, Generation’s recovery of wholesale costs and profits may be limited. In addition, if restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

 

FERC has required electric transmission services to be offered unbundled from commodity sales since 1996. Although this encourages wholesale market transactions for electricity, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Generation also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. The expansion of PJM and the growth of other RTOs mitigate this risk to a degree as RTOs facilitate bilateral transactional activity in the physical wholesale markets wholly within those RTOs without any need to secure transmission service.

 

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 compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. Generation’s cash flows from generation that is not used to meet 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 or energy 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

 

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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.

 

Generation’s credit risk profile is anticipated to change based on the creditworthiness of new and existing counterparties, including ComEd and Ameren. Additionally, due to the possibility of rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of electricity. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets. For additional information on the ComEd auction and the various regulatory proceedings and possible legislative actions, see Note 4 of the Combined Notes to Consolidated Financial Statements.

 

In addition, the retail businesses subject Generation to credit risk resulting from a different customer base.

 

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, 2006, it would have been required to provide approximately $880 million in collateral.

 

Immature Markets. Certain wholesale spot markets are new and 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. This activity 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. Generation plans its business based upon normal weather assumptions. 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 capacity and transmission, limiting Generation’s ability to source or send power to where it is sold. These conditions, which may not have been fully anticipated, 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.

 

Generation’s risk management policies cannot fully eliminate the risk associated with its energy trading activities.

 

Power Team's power trading (including fuel procurement and power marketing) 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

 

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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 power trading 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. Generation’s results of operations could be adversely affected if Generation were unable to effectively manage its capital projects.

 

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

 

Generation depends on coal, natural gas and nuclear fuel assemblies to operate its generating facilities. Coal is procured for coal-fired plants through annual, short-term and spot-market purchases. Natural gas is procured through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term uranium concentrate inventory and supply contracts, contracted conversion services, contracted enrichment services and fuel fabrication services. The supply markets for coal, natural gas and nuclear fuel assemblies are subject to price fluctuations and availability restrictions that may negatively affect the results of operations for Generation. It is not possible to predict the ultimate cost or availability of these commodities. 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.

 

ComEd and PECO

 

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

 

Regulatory Risks

 

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, which may not be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. For example, in ComEd’s most recent rate cases in Illinois, the ICC took eleven months to issue its orders which were followed by rehearing proceedings and numerous appeals.

 

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

 

ComEd and PECO cannot predict the ultimate outcomes of any settlements or the actions by the Illinois and Pennsylvania state regulators for establishing rates. Nevertheless, the expectation is that

 

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ComEd and PECO will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR obligations, whereby each utility is required to provide electricity service to 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.

 

ComEd’s and PECO’s established rates are subject to subsequent prudency reviews by the state regulators.

 

The ICC and PAPUC can adjust various portions of ComEd’s and PECO’s, respectively, established rates, including rates for the procurement of electricity and the recovery of MGP remediation costs, in the regulatory process as a result of subsequent prudency reviews. The prudency reviews add uncertainty to established rates.

 

Increases in customer rates 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.

 

Effective January 2007, ComEd’s customer rates for delivery service and procurement of electricity increased. Additionally, ComEd’s residential customers have the choice to elect to defer certain increases to future periods. See Note 4 of the Combined Notes to the Consolidated Financial Statements for more information. PECO’s 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 Electric Restructuring Settlement and the PECO/Unicom Merger Settlement Agreements. Due to increased rates and the future collection of deferred balances, ComEd and PECO may experience a greater amount of uncollectible customer balances.

 

ComEd may file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code if rate rollback and freeze legislation is enacted into law.

 

In January 2007, ComEd began billing customers under new rates approved by the ICC. These rates reflect the pricing in supplier forward contracts entered into as a result of a reverse-auction competitive bidding process for ComEd’s procurement of electricity. Various governmental and consumer groups have opposed the increased rates that are a byproduct of this auction, and legislation previously proposed in the Illinois House that, if enacted, would provide for a rate rollback and three-year rate freeze extension. If such legislation is enacted into law, ComEd would have contractual obligations to purchase electricity under the supplier forward contracts at prices higher than the rates it would be allowed to collect from its customers for electricity. ComEd has estimated that it could incur operating losses of approximately $1.4 billion per year ($850 million after taxes) or more, depending on various factors, if rates were rolled back and the transition period rate freeze is extended through 2009. Also, ComEd’s ability to obtain new financing or the ability to refinance maturing debt instruments in 2007, would be severely limited due to expected shortfalls in cash flow, likely further credit downgrades to below investment grade and the threat of a bankruptcy filing. ComEd’s projected cash shortfall under a rate freeze extension is anticipated to be approximately $1.4 billion or more in 2007. If rate rollback and rate freeze legislation is passed and allowed to take effect, the associated negative financial implications could lead ComEd to file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

 

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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, 2006, 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 and Comprehensive Income (Loss). 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, 2006, the income statement gain could have been as much as $2.3 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2006, the income statement charge could have been as much as $3.7 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an income statement 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 of up to $1.4 billion (before taxes) 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 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory issues, ComEd’s goodwill and regulatory assets and liabilities, respectively.

 

Mandatory RPS could negatively affect ComEd’s and PECO’s costs.

 

Federal or state legislation mandating the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, could result in significant changes in ComEd’s and PECO’s businesses, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. ComEd and PECO continue to monitor developments related to RPSs at the Federal and state levels.

 

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

 

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

 

On November 7, 2006, FERC established hearing procedures to review the cost allocations proposed by PJM for a number of PJM mandated RTEP projects that will be placed into service over the next three years. ComEd and PECO did not challenge PJM’s allocations of cost to them but, due to the uncertain scope of the matter and the nature of certain allocation issues specifically reserved for hearing, the matter may have an adverse impact on ComEd’s and PECO’s operating costs in the future.

 

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. One Pennsylvania state legislator recently submitted legislation to the

 

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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 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 risk.

 

PECO may be required to change various business processes as a result of PAPUC management audit findings.

 

Under Pennsylvania law, a public utility is subject to a broad management and operations audit conducted by the PAPUC or a consultant hired by the PAPUC every five to eight years. PECO is currently undergoing such an audit by a consultant hired by the PAPUC. Areas of the audit include, among others, electric and gas operations, corporate governance, customer service, and affiliate relations. A final audit report is expected to be issued by the PAPUC in the third quarter of 2007. The audit could result in recommendations that PECO change various business processes to improve its effectiveness in providing electric and gas service to its customers.

 

Financial and Operating Risks

 

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 the event of extended outages affecting large numbers of its customers.

 

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 gas cost charges, which provide no return or profit to PECO, and distribution charges, which provide a return or profit to PECO. Purchased 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 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 gas is purchased and the ultimate recovery from customers.

 

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When purchased gas cost charges increase substantially reflecting higher 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 gas cost charges to customers also may result in increased bad debt expense from an increase in the number of uncollectible customer balances.

 

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 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 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 or if they do not receive full recovery of their own respective capital costs through future regulatory proceedings.

 

Other

 

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

 

Exelon and ComEd had approximately $2.7 billion of goodwill recorded at December 31, 2006 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 2007 or later periods. The actual timing and amounts of any goodwill impairments in future years 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 post-2006 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.

 

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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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 may be negatively affected by possible state legislative or regulatory actions that could limit the retail price of electricity or place burdens on its generation business.

 

Criticism of restructured electricity markets in public forums escalated during 2006 as retail rate freezes expired in a number of states as fuel prices increased, thereby driving up retail prices for electricity. ComEd’s customers are experiencing increases in their costs for electric service beginning in 2007, and PECO’s customers could expect to see increases in their electric bills after 2010. Consumers in other states are also experiencing significant rate increases. In Illinois, Pennsylvania and other states, there is growing pressure for state regulatory and political processes to take steps to reduce the impact of price increases on retail customers. The political pressure for states to retreat from allowing competitively-priced supplies to serve retail load and to return to cost-based regulation of generation resources or take other actions directed at generators of electricity creates heightened risk of limitations on the retail price of electricity, which could significantly affect the results of operations of ComEd and PECO, and a heightened risk of imposition of restrictions and other burdens on Exelon’s generation business, which could significantly affect Generation’s results of operations.

 

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 for electricity increased with rising fuel prices, is expected to continue in 2007. A number of advocacy groups have urged FERC to reconsider its support for competitive wholesale electricity markets, and to 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. FERC has announced that it will convene a series of public conferences during 2007 to address the issues surrounding electric competition. While FERC has not proposed to revise its pricing rules, these events create heightened risk of changes in FERC’s rules governing wholesale electricity markets, which in turn could significantly affect Generation’s results of operations.

 

In addition, FERC has proposed to revise the tests that market participants must satisfy to be entitled to market-based rates. The actual impacts of any new rules that are approved as a result of FERC’s future ruling related to market-based rates could significantly affect Generation’s results of operations.

 

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. As a result of the regulatory recovery process for ComEd and PECO, rate caps for PECO and price pressures due to competition, ComEd and PECO may not be able to recover the costs of inflation from their customers on a timely basis.

 

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 or other increasing costs, their results of operations could be negatively affected.

 

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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. A decline in the market value of the assets, as was experienced from 2000 to 2002, may increase the funding requirements of these obligations. 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 stock of 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. Under applicable Federal law, Generation, ComEd and PECO can pay dividends only from the amount of retained, undistributed or current earnings. 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, ComEd did not pay any dividend.

 

Exelon and Generation will be negatively affected if ComEd files for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

 

There is a risk that ComEd will be required to seek protection in bankruptcy if legislation is enacted in Illinois to extend the rate freeze that expired in January 2007. Exelon anticipates that a bankruptcy filing by ComEd would have significant adverse consequences for Exelon and Generation. These adverse consequences may include, but are not limited to: a significant loss in value of Exelon’s investment in ComEd; possible dilution of Exelon’s ownership interest in ComEd; possible reductions in credit ratings which could increase borrowing costs; uncertainty in collection of receivables from ComEd for services provided by BSC; uncertainty in the enforcement of Generation’s rights under its supplier forward contracts with ComEd and possible rejection of the supplier forward contracts in a ComEd bankruptcy; significant legal and other costs associated with the bankruptcy filing; possible negative income tax consequences; and possible reduced ability to effectively administer and allocate the costs of the various Exelon-sponsored benefit plans. These items, along with other possible negative effects of a ComEd bankruptcy, could have a material adverse effect on Exelon’s and Generation’s results of operations, financial position and cash flows.

 

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, will be subject to mandatory reliability standards promulgated by NERC and enforced by FERC. These standards are currently being applied on a

 

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voluntary basis and are expected to become mandatory in June 2007. The standards are based on the functions that need to be performed to ensure the bulk electric 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. 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 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, 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.

 

Select northeast and mid-Atlantic states have developed a model rule, via the RGGI, to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to regulate carbon emissions could occur in the future. If these plans become effective, Exelon and Generation may incur costs to either further limit the emissions from certain of their fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies.

 

For additional information regarding environmental matters, including nuclear generating station groundwater, see “Environmental Regulation” in ITEM 1 of this Form 10-K.

 

War, acts and threats of terrorism and natural disaster 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

 

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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, the continuing military activity in Iraq, Afghanistan and other wars may have an adverse effect on the economy in general. 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 or war may affect Exelon’s results of operations and its 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.

 

Changes in the availability and cost of insurance mean that the Registrants have greater exposure to economic loss due to property damage and liability.

 

The Registrants carry property damage and liability insurance for their properties and operations. As a result of significant changes in the insurance marketplace, the available coverage and limits may be less than the amount of insurance obtained in the past, the costs of obtaining such insurance may be higher and the recovery for losses due to terrorist acts may be limited. The Registrants are self-insured for deductibles and to the extent that any losses may exceed the amount of insurance maintained. A claim that exceeds the amounts available under property damage and liability insurance, together with the deductible, could negatively affect the Registrants’ results of operations.

 

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.

 

Tax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations 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 Internal Revenue Service (IRS), such as Exelon’s decision to defer the tax gain on ComEd’s 1999 sale of its fossil generating assets. 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. Other than as noted below, the Registrants do not record valuation allowances for 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 state income taxes and fees. Due to the revenue needs of the states in which the Registrants operate, various state income tax and fee increases have been proposed or are being 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 state income tax expense and could have a negative impact on the Registrants’ results of operations and cash flows.

 

In connection with the first reverse-auction competitive bidding process, which took place in Illinois during September 2006, Exelon assessed any impacts from the results of the auction on its state

 

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income tax obligations and considered potential strategies and/or alternative interpretations that may be employed to mitigate these impacts. As a result, Exelon does not believe the results of the auction will significantly affect the provision for state income taxes reported by Exelon on an annual basis. However, management’s estimates of future income tax rates are affected by various factors and actual income tax obligations may differ from management’s estimates. See Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding the reverse-auction competitive bidding process.

 

1999 sale of fossil generating assets. Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to applicable law. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a sale leaseback transaction into which ComEd entered in connection with the fossil plant sale is proper pursuant to applicable law. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. The IRS has indicated its position that the ComEd sale leaseback transaction is substantially similar to a leasing transaction, a sale-in, lease-out (SILO), the IRS is treating as a “listed transaction” pursuant to guidance it issued in 2005. A listed transaction is one that the IRS considers to be a potentially abusive tax shelter. As a result of the IRS characterization of the lease transaction as a listed transaction, the IRS is likely to vigorously challenge the transaction and has sought to obtain information not normally requested in audits. Exelon disagrees with the IRS’ characterization of its sale leaseback as a SILO and believes its position is correct under the tax law and will aggressively defend that position upon audit and any subsequent appeals or litigation.

 

In November 2006, ComEd received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its position that proceeds from the fossil plant sales resulted from an “involuntary conversion.” ComEd plans to protest this adjustment following receipt of the final IRS audit report, which is expected in late 2007.

 

A successful IRS challenge to ComEd’s positions would accelerate future income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2006, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $960 million. If the deferral were successfully challenged by the IRS, it could negatively affect Exelon’s results of operations by as much as $166 million (after tax) related to interest expense. See Note 12 of the Combined Notes to Consolidated Financial Statements for further detail.

 

Investments in synthetic fuel-producing facilities. Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. Section 45K of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45K contains a provision under which tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. Recent events, such as terrorism, natural disasters and strong worldwide demand, have significantly increased the price of domestic crude oil and, therefore, have created uncertainty as to the value of future synthetic fuel tax credits. At December 31, 2006, Exelon has estimated the 2007 phase-out of tax credits to be 18%. This estimate for 2007 may change significantly due to the volatility of oil prices. Absent any efforts to mitigate price exposure, a phase-out could result in the reduction of non-operating net income generated by the investments. See Note 12 of the Combined Notes to Consolidated Financial Statements, the Executive Overview and Liquidity and Capital Resources in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

 

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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 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 could have a material impact on the financial statements of Exelon and its subsidiaries. See Note 18 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 pursue investments that fit their strategic objectives and improve their financial performance. With the repeal of PUHCA, the Registrants are free to make investments and pursue mergers and acquisitions that were formerly not permitted under PUHCA and that might present more risk than the types of investments and mergers and acquisitions that were permitted under PUHCA. However, with the repeal of PUHCA, 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.

 

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, 2006. The table does not include properties held by equity method investments:

 

Station

  Location   No. of
Units
  Percent
Owned (a)
 

Primary

Fuel Type

 

Primary
Dispatch

Type (e)

 

Net

Generation
Capacity (MW) (b)

 

Nuclear (c)

           

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   1,048  

Dresden

  Morris, IL   2     Uranium   Base-load   1,742  

LaSalle

  Seneca, IL   2     Uranium   Base-load   2,288  

Limerick

  Limerick Twp., PA   2     Uranium   Base-load   2,302  

Oyster Creek

  Forked River, NJ   1     Uranium   Base-load   625  

Peach Bottom

  Peach Bottom Twp., PA   2   50.00   Uranium   Base-load   1,135  (d)

Quad Cities

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

Salem

  Hancock’s Bridge, NJ   2   42.59   Uranium   Base-load   969  (d)

Three Mile Island

  Londonderry Twp, PA   1     Uranium   Base-load   837  
               
            16,945  

 

(continued on next page)

 

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Station

  Location   No. of
Units
  Percent
Owned (a)
 

Primary

Fuel Type

 

Primary
Dispatch

Type (e)

 

Net

Generation
Capacity (MW) (b)

 

Fossil (Steam Turbines)

         

Conemaugh

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

Cromby 1

  Phoenixville, PA   1     Coal   Intermediate   147  

Cromby 2

  Phoenixville, PA   1     Oil/Gas   Intermediate   211  

Eddystone 1, 2

  Eddystone, PA   2     Coal   Intermediate   599  

Eddystone 3, 4

  Eddystone, PA   2     Oil/Gas   Intermediate   760  

Fairless Hills

  Falls Twp, PA   2     Landfill Gas   Peaking   60  

Handley 4, 5

  Fort Worth, TX   2     Gas   Peaking   916  

Handley 3

  Fort Worth, TX   1     Gas   Intermediate   400  

Keystone

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

Mountain Creek 2, 6, 7

  Dallas, TX   3     Gas   Peaking   273  

Mountain Creek 8

  Dallas, TX   1     Gas   Intermediate   550  

New Boston 1

  South Boston, MA   1     Gas   Intermediate   355  

Schuylkill

  Philadelphia, PA   1     Oil   Peaking   175  

Wyman

  Yarmouth, ME   1   5.89   Oil   Intermediate   36  (d)
               
            5,191  

Fossil (Combustion Turbines)

         

Chester

  Chester, PA   3     Oil   Peaking   54  

Croydon

  Bristol Twp., PA   8     Oil   Peaking   497  

Delaware

  Philadelphia, PA   4     Oil   Peaking   74  

Eddystone

  Eddystone, PA   4     Oil   Peaking   76  

Falls

  Falls Twp., PA   3     Oil   Peaking   60  

Framingham

  Framingham, MA   3     Oil   Peaking   41  

LaPorte

  Laporte, TX   4     Gas   Peaking   160  

Medway

  West Medway, MA   3     Oil/Gas   Peaking   172  

Moser

  Lower Pottsgrove Twp., PA   3     Oil   Peaking   60  

New Boston

  South Boston, MA   1     Oil   Peaking   18  

Pennsbury

  Falls Twp., PA   2     Landfill Gas   Peaking   6  

Richmond

  Philadelphia, PA   2     Oil   Peaking   132  

Salem

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

Schuylkill

  Philadelphia, PA   2     Oil   Peaking   38  

Southeast Chicago

  Chicago, IL   8     Gas   Peaking   312  

Southwark

  Philadelphia, PA   4     Oil   Peaking   72  
               
            1,788  

Fossil (Internal Combustion/Diesel)

         

Conemaugh

  New Florence, PA   4   20.72   Oil   Peaking   (d)

Cromby

  Phoenixville, PA   1     Oil   Peaking   3  

Delaware

  Philadelphia, PA   1     Oil   Peaking   3  

Keystone

  Shelocta, PA   4   20.99   Oil   Peaking   2 (d)

Schuylkill

  Philadelphia, PA   1     Oil   Peaking   3  
               
            13  

Hydroelectric

           

Conowingo

  Harford Co., MD   11     Hydroelectric   Base-load   536  

Muddy Run

  Lancaster, PA   8     Hydroelectric   Intermediate   1,070  
               
            1,606  
                 

Total

    126         25,543  
                 

(a) 100%, unless otherwise indicated.
(b) For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.
(c) All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.
(d) Net generation capacity is stated at proportionate ownership share.

 

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(e) 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.

 

The net generation capability available for operation at any time may be less due to regulatory restrictions, fuel restrictions, efficiency of cooling facilities 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 property 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 and PECO

 

The electric substations and a portion of the transmission rights of way are located on property owned by ComEd and PECO. A significant portion of the electric transmission and distribution facilities is located over or under highways, streets, other public places or property owned by others, for which permits, grants, easements or licenses, deemed satisfactory by ComEd and PECO but without examination of underlying land titles, have been obtained.

 

Transmission and Distribution

 

ComEd’s and PECO’s higher voltage electric transmission lines owned and in service at December 31, 2006 were as follows:

 

     Voltage (Volts)    Circuit Miles  

ComEd

   765,000    90  
   345,000    2,621  
   138,000    2,867  
   69,000    149  

PECO

   500,000    188 (a)
   220,000    541  
   132,000    156  
   66,000    153  

(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.

 

ComEd’s electric distribution system includes 43,197 circuit miles of overhead lines and 34,917 cable miles of underground lines. PECO’s electric distribution system includes 12,811 circuit miles of overhead lines and 15,224 cable miles of underground lines.

 

Gas

 

The following table sets forth PECO’s gas pipeline miles at December 31, 2006:

 

     Pipeline Miles

Transmission

   31

Distribution

   6,623

Service piping

   5,398
    

Total

   12,052
    

 

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PECO has an LNG facility located in West Conshohocken, Pennsylvania which 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.

 

Mortgages

 

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.

 

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 mortgage bonds are issued.

 

Insurance

 

ComEd and PECO maintain property insurance against loss or damage to their respective properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd and PECO are 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 or PECO.

 

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 18 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

Exelon, Generation, ComEd and PECO

 

None.

 

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PART II

 

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

 

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

 

Exelon

 

Exelon’s common stock is listed on the New York Stock Exchange. As of January 31, 2007, there were 670,157,335 shares of common stock outstanding and approximately 154,087 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:

 

     2006    2005
     Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter
   Fourth
Quarter
   Third
Quarter
   Second
Quarter
   First
Quarter

High price

   $ 63.62    $ 61.98    $ 58.86    $ 59.90    $ 56.00    $ 57.46    $ 52.01    $ 47.18

Low price

     57.83      56.74      51.13      52.79      46.62      49.60      44.14      41.77

Close

     61.89      60.54      56.83      52.90      53.14      53.44      51.33      45.89

Dividends

     0.400      0.400      0.400      0.400      0.400      0.400      0.400      0.400

 

Effective October 24, 2005, Exelon’s Amended and Restated Articles of Incorporation were amended to increase the number of authorized shares of Exelon common stock from 1.2 billion to 2 billion.

 

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock during the fourth quarter of 2006.

 

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, 2006

   10,460    $ 60.55    —      (b )

November 1—November 30, 2006

   —        59.28    2,223,250    (b )
               

Total

   10,460      59.29    2,223,250    (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 share repurchase program has no specified limit and no specified termination date.

 

Generation

 

As of January 31, 2007, Exelon held the entire membership interest in Generation.

 

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ComEd

 

As of January 31, 2007, 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, 2007, 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.

 

PECO

 

As of January 31, 2007, 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.

 

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 may not declare any dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing II or ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing II or ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

 

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2006, 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, 2006, Exelon had retained earnings of $3.4 billion, which includes Generation’s undistributed earnings of $1.8 billion, ComEd’s retained deficit of $(193) million consisting of an unappropriated retained deficit of $(1.6) billion, partially offset by $1.4 billion of retained earnings appropriated for future dividends and PECO’s retained earnings of $584 million.

 

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2006 and 2005:

 

     2006    2005

(per share)

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

Exelon

   $ 0.400    $ 0.400    $ 0.400    $ 0.400    $ 0.400    $ 0.400    $ 0.400    $ 0.400

 

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

 

     2006    2005

(in millions)

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

Generation

   $ 165    $ 122    $ 157    $ 165    $ 108    $ 430    $ 80    $ 239

ComEd

     —        —        —        —        146      107      107      138

PECO

     134      117      135      116      122      116      116      115

 

On December 5, 2006, the Exelon Board of Directors declared a regular quarterly dividend of $0.44 per share on Exelon’s common stock. The dividend is payable on March 10, 2007, to shareholders of record of Exelon at 5:00 p.m. Eastern Standard Time on February 15, 2007. This dividend declaration was made by the Exelon Board of Directors in connection with the Board of Director’s approval of 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. Previously, Exelon had maintained a dividend payout policy of between 50-60% of ongoing operating earnings.

 

During 2006, ComEd did not pay a quarterly 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 Notes to Consolidated Financial Statements. ComEd’s Board of Directors will continue to assess ComEd’s ability to pay a dividend on a quarterly basis.

 

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.

 

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     For the Years Ended December 31,  

in millions, except for per share data

   2006    2005     2004     2003     2002  

Statement of Operations data:

           

Operating revenues

   $ 15,655    $ 15,357     $ 14,133     $ 15,148     $ 14,060  

Operating income

     3,521      2,724       3,499       2,409       3,280  

Income from continuing operations

   $ 1,590    $ 951     $ 1,870     $ 892     $ 1,690  

Income (loss) from discontinued operations

     2      14       (29 )     (99 )     (20 )

Income before cumulative effect of changes in accounting principles

     1,592      965       1,841       793       1,670  

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

     —        (42 )     23       112       (230 )
                                       

Net income (a), (b)

   $ 1,592    $ 923     $ 1,864     $ 905     $ 1,440  
                                       

Earnings per average common share (diluted):

           

Income from continuing operations

   $ 2.35    $ 1.40     $ 2.79     $ 1.36     $ 2.60  

Income (loss) from discontinued operations

     —        0.02       (0.04 )     (0.15 )     (0.03 )

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

     —        (0.06 )     0.03       0.17       (0.35 )
                                       

Net income

   $ 2.35    $ 1.36     $ 2.78     $ 1.38     $ 2.22  
                                       

Dividends per common share

   $ 1.60    $ 1.60     $ 1.26     $ 0.96     $ 0.88  
                                       

Average shares of common stock outstanding—diluted

     676      676       669       657       649  
                                       

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to 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.

 

     December 31,

in millions

   2006    2005    2004    2003    2002

Balance Sheet data:

              

Current assets

   $ 4,992    $ 4,637    $ 3,880    $ 4,524    $ 4,096

Property, plant and equipment, net

     22,775      21,981      21,482      20,630      17,957

Noncurrent regulatory assets

     5,808      4,734      5,076      5,564      6,061

Goodwill (a)

     2,694      3,475      4,705      4,719      4,992

Other deferred debits and other assets

     8,050      7,970      7,867      6,800      5,249
                                  

Total assets

   $ 44,319    $ 42,797    $ 43,010    $ 42,237    $ 38,355
                                  

Current liabilities

   $ 5,795    $ 6,563    $ 4,836    $ 5,683    $ 5,845

Long-term debt, including long-term debt to financing trusts (c)

     11,911      11,760      12,148      13,489      13,127

Noncurrent regulatory liabilities

     2,975      2,518      2,490      2,229      1,001

Other deferred credits and other liabilities (b)

     13,578      12,743      13,918      12,246      9,968

Minority interest

     —        1      42      —        77

Preferred securities of subsidiaries (c)

     87      87      87      87      595

Shareholders’ equity

     9,973      9,125      9,489      8,503      7,742
                                  

Total liabilities and shareholders’ equity

   $ 44,319    $ 42,797    $ 43,010    $ 42,237    $ 38,355
                                  

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charge of $776 million and $1.2 billion in 2006 and 2005, respectively.
(b) Change between 2006 and 2005 was primarily due to the impact of adopting SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158).
(c) Due to the adoption of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities of ComEd and PECO were reclassified as long-term debt to financing trusts in 2003.

 

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Generation

 

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

   2006    2005     2004     2003     2002

Statement of Operations data:

           

Operating revenues

   $ 9,143    $ 9,046     $ 7,703     $ 8,135     $ 6,858

Operating income (loss)

     2,396      1,852       1,039       (115 )     509

Income (loss) from continuing operations

   $ 1,403    $ 1,109     $ 657     $ (241 )   $ 387

Income (loss) from discontinued operations

     4      19       (16 )     —         —  

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

     1,407      1,128       641       (241 )     387

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

     —        (30 )     32       108       13
                                     

Net income (loss) (a)

   $ 1,407    $ 1,098     $ 673     $ (133 )   $ 400
                                     

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

 

     December 31,

(in millions)

   2006    2005    2004    2003    2002

Balance Sheet data:

              

Current assets

   $ 3,433    $ 3,040    $ 2,321    $ 2,438    $ 1,805

Property, plant and equipment, net

     7,514      7,464      7,536      7,106      4,698

Deferred debits and other assets

     7,962      7,220      6,581      5,105      4,402
                                  

Total assets

   $ 18,909    $ 17,724    $ 16,438    $ 14,649    $ 10,905
                                  

Current liabilities

   $ 2,914    $ 3,400    $ 2,416    $ 3,553    $ 2,594

Long-term debt

     1,778      1,788      2,583      1,649      2,132

Deferred credits and other liabilities

     8,736      8,554      8,356      6,488      3,226

Minority interest

     1      2      44      3      54

Member’s equity

     5,480      3,980      3,039      2,956      2,899
                                  

Total liabilities and member’s equity

   $ 18,909    $ 17,724    $ 16,438    $ 14,649    $ 10,905
                                  

 

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ComEd

 

The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,

(in millions)

   2006     2005     2004    2003    2002

Statement of Operations data:

            

Operating revenues

   $ 6,101     $ 6,264     $ 5,803    $ 5,814    $ 6,124

Operating income (loss)

     555       (12 )     1,617      1,567      1,766

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

   $ (112 )   $ (676 )   $ 676    $ 702    $ 790

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

     —         (9 )     —        5      —  
                                    

Net income (loss) (a)

   $ (112 )   $ (685 )   $ 676    $ 707    $ 790
                                    

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

 

     December 31,

(in millions)

   2006    2005    2004    2003    2002

Balance Sheet data:

              

Current assets

   $ 1,007    $ 1,024    $ 1,196    $ 1,313    $ 1,049

Property, plant and equipment, net

     10,457      9,906      9,463      9,096      8,689

Goodwill, net (a)

     2,694      3,475      4,705      4,719      4,916

Noncurrent regulatory assets

     532      280      240      326      515

Other deferred debits and other assets

     3,084      2,806      2,077      2,837      1,662
                                  

Total assets

   $ 17,774    $ 17,491    $ 17,681    $ 18,291    $ 16,831
                                  

Current liabilities

   $ 1,600    $ 2,308    $ 1,764    $ 1,557    $ 2,023

Long-term debt, including long-term debt to financing trusts (b)

     4,133      3,541      4,282      5,887      5,268

Noncurrent regulatory liabilities

     2,824      2,450      2,444      2,217      1,001

Other deferred credits and other liabilities

     2,919      2,796      2,451      2,288      2,451

Mandatorily redeemable preferred securities of subsidiary trusts (b)

     —        —        —        —        330

Shareholders’ equity

     6,298      6,396      6,740      6,342      5,758
                                  

Total liabilities and shareholders’ equity

   $ 17,774    $ 17,491    $ 17,681    $ 18,291    $ 16,831
                                  

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.
(b) Due to the adoption of FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts as of December 31, 2003.

 

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PECO

 

The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

 

     For the Years Ended December 31,

(in millions)


   2006

   2005

    2004

   2003

   2002

Statement of Operations data:

                                   

Operating revenues

   $ 5,168    $ 4,910     $ 4,487    $ 4,388    $ 4,333

Operating income

     866      1,049       1,014      1,056      1,093

Income before cumulative effect of a change in accounting principle

   $ 441    $ 520     $ 455    $ 473    $ 486

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

     —        (3 )     —        —        —  
    

  


 

  

  

Net income

   $ 441    $ 517     $ 455    $ 473    $ 486
    

  


 

  

  

Net income on common stock

   $ 437    $ 513     $ 452    $ 468    $ 478
    

  


 

  

  

 

     December 31,

(in millions)


   2006

   2005

   2004

   2003

   2002

Balance Sheet data:

                                  

Current assets

   $ 762    $ 795    $ 727    $ 659    $ 898

Property, plant and equipment, net

     4,651      4,471      4,329      4,256      4,159

Noncurrent regulatory assets

     3,896      4,454      4,836      5,238      5,546

Other deferred debits and other assets

     464      366      241      232      88
    

  

  

  

  

Total assets

   $ 9,773    $ 10,086    $ 10,133    $ 10,385    $ 10,691
    

  

  

  

  

Current liabilities

   $ 978    $ 936    $ 748    $ 676    $ 1,509

Long-term debt, including long-term debt to financing trusts (a)

     3,784      4,143      4,628      5,239      4,951

Noncurrent regulatory liabilities

     151      68      46      12      —  

Other deferred credits and other liabilities

     3,051      3,235      3,313      3,442      3,342

Mandatorily redeemable preferred securities of subsidiary trusts (a)

     —        —        —        —        128

Shareholders’ equity

     1,809      1,704      1,398      1,016      761
    

  

  

  

  

Total liabilities and shareholders’ equity

   $ 9,773    $ 10,086    $ 10,133    $ 10,385    $ 10,691
    

  

  

  

  


(a) Due to the adoptions of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts in 2003.

 

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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 and wholesale customers in northern Illinois, including the City of Chicago.

 

   

PECO, whose businesses 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 20 of the Combined Notes to Consolidated Financial Statements for further segment information.

 

Exelon’s corporate operations, through its business services subsidiary, BSC, provide Exelon’s business segments with a variety of support services. 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 $1,592 million in 2006 as compared to $923 million in 2005 and diluted earnings per average common share were $2.35 for 2006 as compared to $1.36 for 2005. The increases were primarily due to the following:

 

   

a $1.2 billion impairment charge in 2005 associated with ComEd’s goodwill;

 

   

higher margins on wholesale market sales and increased nuclear output at Generation;

 

   

a one-time benefit of approximately $290 million to recover certain costs approved by the ICC’s July 2006 rate order and the ICC’s December 2006 amended rate order;

 

   

unrealized mark-to-market gains on contracts not yet settled;

 

   

a decrease in Generation’s nuclear asset retirement obligation resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily the AmerGen nuclear plants;

 

   

increased electric revenues at PECO associated with certain scheduled rate increases;

 

   

increased kWh deliveries, excluding the effects of weather, reflecting 2006 load growth at ComEd and PECO;

 

   

losses recorded in 2005 for the cumulative effect of adopting Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47); and

 

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a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims.

 

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

 

   

a $776 million impairment charge associated with ComEd’s goodwill primarily due to the impacts of the ICC’s July 2006 rate order;

 

   

a charge of approximately $55 million for the write-off of capitalized costs associated with the now terminated proposed merger with PSEG;

 

   

increased severance and severance-related charges;

 

   

unfavorable weather conditions in the ComEd and PECO service territories;

 

   

reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset;

 

   

increased depreciation and amortization expense, primarily related to CTC amortization at PECO;

 

   

higher operating and maintenance expenses, including increased nuclear refueling outage costs, increased costs associated with incremental storm damage in the PECO service territory, expenses related to stock-based compensation as a result of adopting Financial Accounting Standards Board Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R) and the impacts of inflation;

 

   

increased interest expense associated with the debt issued in March 2005 to fund Exelon’s pension contributions; and

 

   

gains realized in 2005 on AmerGen’s decommissioning trust fund investments related to changes to the investment strategy.

 

Termination of Proposed Merger with PSEG. On December 20, 2004, Exelon entered into a Merger Agreement with PSEG, a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would be merged with and into Exelon (Merger). On September 14, 2006, Exelon gave formal notice to PSEG that Exelon had terminated the Merger Agreement and the companies agreed to withdraw their application for Merger approval, which had been pending before the NJBPU for more than 19 months. The notice followed a number of discussions with state officials and other interested parties, which made clear that gaps separating the parties’ respective settlement positions were insurmountable. Major differences included, among other things, issues relating to rate concessions and market power mitigation. During 2006, Exelon recorded Merger-related expenses of approximately $93 million (pre-tax), of which $55 million relates to the write-off of the capitalized costs associated with the Merger. Including this $93 million of expenses, total Merger-related expenses incurred since the inception of the Merger discussions were approximately $130 million.

 

Financing Activities. During 2006, Exelon met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including the capital markets, and through bank borrowings. As of December 31, 2006, Exelon, Generation, ComEd and PECO have access to revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion, $1 billion and $600 million, respectively. In addition, ComEd and PECO issued First Mortgage Bonds of $1.1 billion and $300 million, respectively, in 2006. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information on the credit facilities and the bond issuances.

 

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Regulatory and Environmental Developments. The following significant regulatory and environmental developments occurred during 2006. See Notes 4 and 18 of the Combined Notes to Consolidated Financial Statements for further information.

 

   

ComEd Procurement Case—On January 24, 2006, the ICC approved ComEd’s procurement case, authorizing ComEd to procure electricity after 2006 through a “reverse-auction” competitive bidding process and to recover the costs from retail customers with no markup. The first auction took place in September 2006. As a result of the auction, ComEd has entered into supplier forward contracts with various suppliers including Generation. The ICC order is under appeal.

 

   

Illinois Rate Freeze Extension Proposal—In 2006 and 2007, various bills, amendments and “compromise” legislation were separately passed by the Illinois House and the Illinois Senate including, in the Illinois House, an extension of the Illinois transition period rate freeze with a rollback of rates to 2006 levels. However, the Illinois General Assembly adjourned on January 9, 2007 without taking further action on such bills. As a result, all pending legislation expired. ComEd believes any rate rollback and freeze legislation, if proposed again and enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. ComEd believes such legislation would violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such legislation in court.

 

   

ComEd Residential Rate Stabilization—On December 20, 2006, the ICC approved a residential rate stabilization program that allows residential customers the choice to limit the impact of any rate increase over the next three years. For customers choosing to participate in the program, electric rate increases would be capped at 10% in each of 2007, 2008 and 2009. Costs that exceed the caps would be deferred and recovered over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25%. If ComEd’s rate increases are less than the caps in 2008 and 2009, ComEd would begin to recover deferred amounts up to the caps with carrying costs. This order also strongly encouraged, but did not require, ComEd to make contributions totaling $30 million to environmental and customer assistance programs. ComEd is currently evaluating this request. This order is subject to rehearing and appeal.

 

   

ComEd Rate Case—On July 26, 2006, the ICC issued its order in the Rate Case approving a revenue increase of approximately $8 million and the recovery of several items that previously were recorded as expense. On December 20, 2006, the ICC approved an amended order on the rehearing of the Rate Case allowing an additional revenue increase of approximately $74 million, including a partial return on the pension asset, for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. As a result of the July 26, 2006 ICC rate order, ComEd recorded an after-tax impairment charge of $776 million associated with the write-off of goodwill.

 

   

Nuclear Fleet Inspection—In February 2006, Exelon and 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 into the environment. The initiative was in response to the detection of tritium in water samples taken related to leaks at the Braidwood, Byron and Dresden nuclear generating stations in Illinois. 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 where past accidental tritiated water spills have been identified and state-approved cleanup work continues. 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.

 

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Outlook for 2007 and Beyond.

 

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

 

   

If the price at which ComEd is allowed to sell electricity beginning in 2007 is set below ComEd’s cost to procure and deliver electricity, there will be material adverse consequences to ComEd, including possible bankruptcy, which could result in material adverse consequences to Exelon and, in the event of a ComEd bankruptcy filing, possibly material adverse consequences to Generation. The ICC’s unanimous approval of the reverse-auction process, barring any adverse decision in the pending appeals or change in law, should provide ComEd with stability and greater certainty that it will be able to procure electricity and pass through the costs of that electricity to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction competitive bidding process.

 

   

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 or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so. PECO is, however, involved in proceedings involving annual changes in its electric and gas universal service fund cost charges, its electric CTC/intangible transition charge reconciliation mechanism, and its purchased gas cost rate, all of which are designed to fully recover PECO’s applicable costs on a dollar-for-dollar basis.

 

   

Effective January 1, 2007, in accordance with its 1998 restructuring settlement with the PAPUC, PECO implemented an electric generation rate increase that will result in approximately $190 million of additional operating revenues in 2007 as compared to 2006 and a corresponding increase in purchased power from affiliate, in accordance with PECO’s PPA with Generation, with no resulting impact on pre-tax operating income. The impact of this rate increase on Exelon will be an increase in operating revenues and pre-tax operating income of approximately $190 million. The impact on Generation will be an increase in operating revenues from affiliates and pre-tax operating income of approximately $190 million.

 

   

Generation is exposed to commodity price risk associated with the unhedged portion of its electricity trading 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 2007 and 2008. 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.

 

   

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 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 ComEd’s and PECO’s requirements have improved historically due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants.

 

   

Federal and state governing bodies have begun to introduce, and in some cases approve, legislation mandating the future use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal. The extent of the use of these renewable and alternative fuel sources varies by state and could change. The future requirement to use these renewable and alternative fuel sources for some portion of ComEd’s and PECO’s distribution sales could result in increased fuel costs and capital expenditures.

 

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Select northeast and mid-Atlantic states have developed a model rule, via the RGGI, to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to regulate carbon emissions could occur in the future. If these plans become effective, Exelon may incur costs in further limiting the emissions from certain of its fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies. However, Exelon may benefit from stricter emission standards due to its significant nuclear capacity, which is not anticipated to be affected by the proposed emission standards.

 

   

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. 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.

 

   

Exelon pursues growth opportunities that are consistent with its disciplined approach to investing to maximize earnings and cash flows. On September 29, 2006, Generation notified the NRC that Generation will begin the application process for a combined construction and operating license that would allow for the possible construction of a new nuclear plant at an as-yet unnamed location in Texas. The filing of the letter with the NRC launches a process that “preserves for Exelon the option” to develop a new nuclear plant in Texas without immediately committing to the full project. Exelon has not decided to build a new nuclear plant. Among the various conditions that must be resolved before any formal decision to build is made are a permanent solution to spent nuclear fuel disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using new technology can be financially successful. Exelon expects to submit the application to the NRC for the combined construction and operating license in 2008.

 

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 Committee of the Exelon Board 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.

 

Asset Retirement Obligations (ARO) (Exelon, Generation, ComEd and PECO)

 

Nuclear Decommissioning (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).

 

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SFAS No. 143 requires that Generation estimate the fair value of its obligation for the future decommissioning of its nuclear generating plants. To estimate that fair value, 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 prepared by a third party to provide a marketplace assessment of the costs and timing of decommissioning activities which are validated by comparison to current decommissioning projects and other third-party 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, which were prepared using year-of-estimate amounts, through the decommissioning period for each of the units. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy and low-level radioactive waste disposal costs. Cost escalation studies are updated on a periodic basis.

 

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost, decommissioning alternative and timing scenarios. Probabilities assigned to cost levels include an assessment of the likelihood of actual costs plus 20% or minus 15% 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 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) 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 recorded with a corresponding change to the asset retirement cost (ARC) asset. However, if an update to an ARO results in a decrease, and that unit does not have an underlying ARC, that change in the ARO may be recognized in current period earnings. Changes in the assumptions could affect future updates to the decommissioning obligation. For example, the 20-year average cost escalation rates used in the latest ARO calculation were approximately 3% to 4%. A uniform increase in these escalation rates of 25 basis points would increase the total ARO recorded by Exelon by approximately 9% or more than $300 million. 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 amount of the original estimate of the future undiscounted cash flows required to decommission the nuclear plants. For more information regarding the adoption and ongoing application of SFAS No. 143, see Notes 1 and 13 of the Combined Notes to Consolidated Financial Statements.

 

Conditional ARO (Exelon, Generation, ComEd and PECO)

 

As of December 31, 2005, the Registrants adopted FIN 47. FIN 47 clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are

 

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conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, the Registrants are required to record a conditional ARO at its estimated fair value if that fair value can be reasonably estimated.

 

The adoption of FIN 47 required the Registrants to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether their conditional AROs could be reasonably estimated, management considered the Registrants’ past practices, industry practices, management’s intent and the estimated economic lives of the assets. The fair values of the conditional AROs were then estimated using an expected present value technique. Additionally, Exelon, ComEd and PECO assessed the likelihood of recovering these obligations from customers which led to the recognition of regulatory assets. Changes in management’s assumptions regarding settlement dates, settlement methods, assigned probabilities or recovery mechanisms could have a material effect on the liabilities recorded by each Registrant and the associated regulatory assets recorded at Exelon, ComEd and PECO. The liabilities associated with conditional AROs will be adjusted on a periodic basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Operations of the Registrants. For more information regarding the adoption and ongoing application of FIN 47, 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 impairment of their goodwill at least annually or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired, such as a significant negative regulatory outcome. Application of the goodwill impairment test requires management’s judgments, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

 

Due to the significant negative impact of the ICC’s July 26, 2006 order in ComEd’s Rate Case to the future cash flows and value of ComEd, an interim impairment assessment was completed during the third quarter of 2006. Based on the results of ComEd’s interim goodwill impairment analysis, Exelon and ComEd recorded an impairment charge of $776 million associated with the write-off of the goodwill. Exelon and ComEd performed their annual goodwill impairment assessment in the fourth quarter of 2006 and determined that goodwill was not further impaired. Future developments relating to ComEd’s ongoing regulatory and/or legislative items could also be relevant to future goodwill impairment analyses and may lead to further impairments, which could be material. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the Rate Case.

 

In the assessments, Exelon and ComEd estimated the fair value of the ComEd reporting unit using a probability-weighted, discounted cash flow model with multiple scenarios. The fair value incorporates management's assessment of current events and expected future cash flows. Additionally, ComEd’s estimate of its fair value was compared to a fair value estimate determined by a third-party valuation firm. Changes in assumptions regarding variables, including post-2006 rate regulatory structure, ComEd’s capital structure, changing interest rates, utility sector market performance, operating and

 

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capital expenditure requirements and other factors, or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of 10% in ComEd’s expected discounted cash flows would result in additional impairment for both ComEd and Exelon of approximately $800 million. An additional impairment would require Exelon and ComEd to further 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, 2006. The Registrants consider investments to be impaired when a decline in fair value below cost is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, the Registrants evaluate, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as their intent and ability to hold the investment. The Registrants may also consider specific adverse conditions related to the financial health of and business outlook for the investee when reviewing an investment for impairment. An impairment would require the affected registrant to reduce both the investment and current period earnings by the amount of the impairment. 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” (FSP 115-1), Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain NRC restrictions, Generation is unable to demonstrate its ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and, accordingly, recognizes any unrealized holding losses immediately.

 

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

 

The Registrants have a significant investment in electric generation assets and electric and natural gas transmission and distribution assets. Depreciation of these assets is generally provided over their estimated service lives on a straight-line basis using the composite method. The estimation of service lives requires management judgment regarding the period of time that the assets will be in use. As circumstances warrant, the estimated service lives are reviewed to determine if any changes are needed. Changes to depreciation estimates in future periods could have a significant impact on the amount of property, plant and equipment recorded and the depreciation charged to the financial statements.

 

Historically, Generation has extended the estimated service lives of the nuclear-fuel generating facilities based upon Generation’s intent to apply for license renewals for these facilities. 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

 

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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 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.

 

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 BSC employees, except for those employees of Generation’s wholly owned subsidiary, AmerGen, who participate in the separate AmerGen-sposored defined benefit pension plan and other postretirement welfare benefit plan. See Note 14—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 costs of providing benefits under these plans are dependent on historical information such as employee age, length of service and level of compensation and the actual rate of return on plan assets. Also, Exelon and AmerGen utilize assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the remaining service period, rate of compensation increases and the anticipated rate of increase in health care costs, in order to measure the plan obligations and costs to be recognized related to these plans.

 

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 9.00% for 2006, 2005, and 2004. The weighted average EROA assumption used in calculating other postretirement benefit costs was 8.15% and 8.30% in 2006 and 2005, respectively, and a range of 8.33% to 8.35% in 2004. 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 average remaining service period of defined pension plan participants was 13.5 years, 13.8 years and 15.1 years for the years ended December 31, 2006, 2005 and 2004, respectively. The average remaining service period of postretirement benefit plan participants related to eligibility age was 7.3 years, 7.5 years and 8.7 years for the years ended December 31, 2006, 2005 and 2004, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 10.3 years, 10.9 years and 11.9 years for the years ended December 31, 2006, 2005 and 2004, respectively.

 

The discount rate for determining the pension benefit obligations was 5.90%, 5.60% and 5.75% at December 31, 2006, 2005 and 2004, respectively. The discount rate for determining the other postretirement benefit obligations was 5.85%, 5.60% and 5.75% at December 31, 2006, 2005 and 2004, respectively. The discount rate at December 31, 2004 was selected by reference to the Moody’s Aa Corporate Bond Index adjusted to reflect the duration of expected future cash flows for pension and other postretirement benefit payments. At December 31, 2006 and 2005, the discount rate was

 

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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.

 

Exelon will use a discount rate and EROA of 5.90% and 8.75%, respectively, for estimating its 2007 pension costs. Additionally, Exelon will use a discount rate and expected return on plan assets of 5.85% and 7.87%, respectively, for estimating its 2007 other postretirement benefit costs.

 

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

 

Change in Actuarial Assumption

  

Impact on

Projected Benefit

Obligation at

December 31, 2006

  

Impact on

Pension Liability at

December 31, 2006

  

Impact on

2007

Pension Cost

Pension benefits

        

Decrease discount rate by 0.5%

   $ 720    $ 720    $ 57

Decrease rate of return on plan assets by 0.5%

     —        —        47

Change in Actuarial Assumption

  

Impact on

Other

Postretirement

Benefit Obligation

at December 31, 2006

  

Impact on

Postretirement

Benefit Liability at

December 31, 2006

  

Impact on 2007

Postretirement

Benefit Cost

Postretirement benefits

        

Decrease discount rate by 0.5%

   $ 225    $ 225    $ 26

Decrease rate of return on plan assets by 0.5%

     —        —        7

 

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, 2006 postretirement benefit obligation and estimated 2006 costs (dollars in millions):

 

Change in Actuarial Assumption

  

Impact on

Other

Postretirement

Benefit

Obligation at

December 31, 2006

   

Impact on

2006

Total
Service and

Interest Cost
Components

 

Increase assumed health care cost trend by 1%

   $ 45     $ 418  

Decrease assumed health care cost trend by 1%

     (37 )     (345 )

 

Extending the year at which the ultimate health care trend rate of 5% is forecasted to be reached from 2012 to 2017 would have had the following effects on the December 31, 2006 postretirement benefit obligation and estimated 2006 costs (dollars in millions):

 

Change in Actuarial Assumption

  

Impact on

Other
Postretirement

Benefit

Obligation at
December 31, 2006

  

Impact on
2006

Total Service
and
Interest Cost
Components

Increase the year at which the ultimate health care trend rate of 5% is forecasted to be reached from 2012 to 2017

   $ 234    $ 22

 

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The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes is reflected in the recorded pension and postretirement benefit amounts as they occur, or over a period of time if allowed under applicable accounting standards. As these assumptions change from period to period, recorded pension and postretirement benefit amounts and funding requirements could also change.

 

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. Use of SFAS No. 71 is 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, 2006, 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 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 and Comprehensive Income (Loss). 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, 2006, the income statement gain could have been as much as $2.3 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, 2006, the income statement charge could have been as much as $3.7 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. In that event, Exelon would record an income statement gain or charge in an equal amount related to ComEd’s and/or PECO’s regulatory assets and liabilities in addition to a charge against other comprehensive income of up to $1.4 billion (before taxes) 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 could limit the ability of ComEd and PECO to pay dividends under Federal and state law. See Notes 4, 8 and 19 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 where 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, recent rate orders to other regulated entities in the same jurisdiction and the ability to recover costs through regulated rates.

 

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

 

The Registrants may enter into derivatives 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 utilizes derivatives with respect to energy transactions to the utilization of its available generating capability and the supply of wholesale energy to its affiliates. Generation

 

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also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk exposure associated with forward energy commodity prices. Additionally, Generation enters into energy-related derivatives for trading purposes. ComEd has derivatives related to one wholesale contract and certain other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. ComEd does not enter into derivatives for speculative or trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

 

The Registrants account for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133). 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. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings when the hedged transaction occur. Amounts recorded in earnings are included in revenue, purchased power or fuel in the consolidated statements of income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the statement of cash flows, depending on the underlying nature of the Registrant’s hedged items.

 

Normal Purchases and Normal Sales Exception. The availability of the normal purchases and normal sales exception is based upon the assessment of the ability and intent to deliver or take delivery of the underlying item. If it was 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. In September 2006, Generation participated in and won portions of the ComEd and Ameren procurement auctions. As a result of the expiration of Generation’s PPA with ComEd at the end of 2006 and the results of the auctions, beginning in 2007, Generation will sell more power through bilateral agreements with other new and existing counterparties. ComEd also entered into agreements with thirteen other suppliers as part of the auction. Generation’s and ComEd’s agreements meet the normal purchases and normal sales exception.

 

Energy Contracts. Identification of an energy 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 energy contract and the expected future purchase or sale of energy 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 an energy 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 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

 

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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. 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 use external dealer prices and/or internal valuation models that utilize assumptions of available market pricing curves.

 

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.

 

Taxation

 

The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations 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 related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. The Registrants also estimate 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 related to capital losses that the Registrants believe will be realized in future periods. While the Registrants believe the resulting tax reserve balances as of December 31, 2006 reflect the probable expected outcome of pending tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” SFAS No. 109, “Accounting for Income Taxes,” and Statement of Financial Accounting Concepts No. 6, Elements of Financial Statements—a replacement of FASB Concepts Statement No. 3 (incorporating an amendment of FASB Concepts Statement No. 2)”, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.

 

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.

 

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.

 

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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, 2006 and for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Exelon’s 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 and the actuaries 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 related to asbestos exposure and the anticipated levels of awards made to plaintiffs. Exelon plans to obtain annual 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 third-party 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. Management cautions, however, that 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.

 

Severance Accounting (Exelon, Generation, ComEd and PECO)

 

The Registrants provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with the Registrants and compensation level. The Registrants accrue severance benefits that are considered probable and can be reasonably estimated in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112). A significant assumption in estimating severance charges is the determination of the number of positions to be eliminated. The Registrants base their estimates on their current plans and ability to determine the appropriate staffing levels to effectively operate their businesses. The Registrants may incur further severance costs if they identify additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

 

Stock-Based Compensation Cost (Exelon, Generation, ComEd and PECO)

 

On January 1, 2006, Exelon adopted SFAS No. 123-R, which requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost is measured on the fair value of the equity or liability instruments at the date of grant and amortized over the vesting period. The fair value of stock options on the date of grant is estimated using the Black-Scholes-Merton option-pricing model, which requires assumptions such as dividends yield, expected volatility, risk-free interest rate, expected life and forfeiture rate. The fair value of performance share awards granted in 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year, which requires assumptions regarding Exelon’s

 

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total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. If the actual results of the cash-settled performance share awards differ significantly from the estimates, the Consolidated Financial Statements could be materially affected. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.

 

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. This 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, such as the nuclear Operating Service Agreement with PSEG Nuclear, 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.

 

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

 

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

 

Results of Operations—Exelon

 

      2006     2005     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 15,655     $ 15,357     $ 298  

Operating expenses

      

Purchased power and fuel

     5,232       5,670       438  

Operating and maintenance

     3,868       3,694       (174 )

Impairment of goodwill

     776       1,207       431  

Depreciation and amortization

     1,487       1,334       (153 )

Taxes other than income

     771       728       (43 )
                        

Total operating expenses

     12,134       12,633       499  
                        

Operating income

     3,521       2,724       797  

Other income and deductions

      

Interest expense

     (616 )     (513 )     (103 )

Interest expense to affiliates, net

     (264 )     (316 )     52  

Equity in losses of unconsolidated affiliates

     (111 )     (134 )     23  

Other, net

     266       134       132  
                        

Total other income and deductions

     (725 )     (829 )     104  
                        

Income from continuing operations before income taxes

     2,796       1,895       901  

Income taxes

     1,206       944       (262 )
                        

Income from continuing operations

     1,590       951       639  

Income from discontinued operations, net of income taxes

     2       14       (12 )
                        

Income before cumulative effect of a change in accounting principle

     1,592       965       627  

Cumulative effect of changes in accounting principles

     —         (42 )     42  
                        

Net income

   $ 1,592     $ 923     $ 669  
                        

Diluted earnings per share

   $ 2.35     $ 1.36     $ 0.99  

 

Net Income. Exelon’s net income for 2006 reflects higher realized prices on market sales and increased nuclear output at Generation; a one-time benefit of approximately $158 million to recover previously incurred severance costs approved by the December 2006 amended ICC rate order; a one-time benefit of approximately $130 million to recover certain costs approved by the July 2006 ICC rate order; a decrease in Generation’s nuclear ARO resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily AmerGen nuclear plants; unrealized mark-to-market gains; increased electric revenues at PECO associated with certain authorized rate increases; and increased kWh deliveries, excluding the effects of weather, reflecting load growth at ComEd and PECO. These increases were partially offset by a $776 million impairment charge associated with ComEd’s goodwill; unfavorable weather conditions in both the ComEd and PECO service territories; a charge of approximately $55 million for the write-off of capitalized costs associated with the terminated proposed Merger with PSEG; increased severance and severance-related charges; losses from investments in synthetic fuel-producing facilities; increased depreciation and amortization expense, including CTC amortization at PECO; and higher operating and maintenance expenses including increased costs associated with storm damage in the PECO service territory, increased nuclear refueling outage costs, increased stock-based compensation expense as a result of adopting SFAS No. 123-R, and the impacts of

 

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inflation. Exelon’s net income for 2005 reflects an impairment charge of $1.2 billion associated with ComEd’s goodwill; unrealized mark-to-market losses; losses of $42 million for the cumulative effect of adopting FIN 47; favorable tax settlements at Generation and PECO; and gains realized on AmerGen’s decommissioning trust fund investments related to changes in the investment strategy.

 

Operating Revenues. Operating revenues increased primarily due to an increase in wholesale and retail electric sales at Generation due to an increase in market prices; higher nuclear output; electric rate increases at PECO; and higher kWh deliveries at ComEd and PECO, excluding the effects of weather. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories. See further analysis and discussion of operating revenues by segment below.

 

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased due to lower volumes of power purchased in the market and decreased fossil generation, partially offset by overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 20% of Generation’s total supply in 2006 compared to 22% for 2005. See further analysis and discussion of purchased power and fuel expense by segment below.

 

Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to a charge of approximately $55 million for the write-off of capitalized costs associated with the terminated proposed Merger with PSEG; increased nuclear refueling outage costs; increased severance and severance-related charges; increased stock-based compensation expense as a result of adopting SFAS No. 123-R; and the impacts from inflation. These increases were partially offset by a one-time benefit of $201 million to recover certain costs approved by the ICC’s July 2006 rate order and the ICC’s December 2006 amended rate order; the impact of the reduction in Generation’s estimated nuclear asset retirement obligation; mark-to-market gains associated with Exelon’s investment in synthetic fuel-producing facilities; and a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims. 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. During 2005, in connection with the annually required assessment of goodwill for impairment, ComEd recorded a $1.2 billion charge.

 

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO and additional plant placed in service.

 

Taxes Other Than Income. Taxes other than income increased primarily due to a reduction in 2005 of previously established real estate tax reserves at PECO and Generation and a net increase in utility revenue taxes at ComEd and PECO in 2006, partially offset by favorable state franchise tax settlements at PECO in 2006.

 

Other Income and Deductions. The change in other income and deductions reflects increased interest expense associated with the debt issued in 2005 to fund Exelon’s voluntary pension contribution; higher interest rates on variable rate debt outstanding; higher interest expense on Generation’s one-time fee for pre-1983 spent nuclear fuel obligations to the DOE; an interest payment to the IRS associated with the settlement of a tax matter at Generation; and a one-time benefit of $87 million approved by the ICC’s July 2006 rate order to recover previously incurred debt expenses to retire debt early .

 

Effective Income Tax Rate. The effective income tax rate from continuing operations was 43.1% for 2006 compared to 49.8% for 2005. The goodwill impairment charges increased the effective income

 

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tax rate from continuing operations by 9.7% and 22.3% for 2006 and 2005, respectively. See Note 12 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

 

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. In addition, Exelon has sold or wound down substantially all components of 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 and Comprehensive Income. 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. The results of Sithe are included in the Generation discussion below.

 

The income from discontinued operations decreased by $12 million for 2006 compared to 2005 primarily due to the gain on the sale of Sithe in 2005 partially offset by an adjustment to the gain on the sale of Sithe in 2006 as a result of the expiration of certain tax indemnifications.

 

Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles reflects the impact of adopting FIN 47 as of December 31, 2005. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

 

Results of Operations by Business Segment

 

The comparisons of 2006 and 2005 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

 

     2006     2005     Favorable
(unfavorable)
variance
 

Generation

   $ 1,403     $ 1,109     $ 294  

ComEd

     (112 )     (676 )     564  

PECO

     441       520       (79 )

Other (a)

     (142 )     (2 )     (140 )
                        

Total

   $ 1,590     $ 951     $ 639  
                        

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

 

Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment

 

     2006     2005     Favorable
(unfavorable)
variance
 

Generation

   $ 1,407     $ 1,128     $ 279  

ComEd

     (112 )     (676 )     564  

PECO

     441       520       (79 )

Other (a)

     (144 )     (7 )     (137 )
                        

Total

   $ 1,592     $ 965     $ 627  
                        

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

 

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Net Income (Loss) by Business Segment

 

     2006     2005     Favorable
(unfavorable)
variance
 

Generation

   $ 1,407     $ 1,098     $ 309  

ComEd

     (112 )     (685 )     573  

PECO

     441       517       (76 )

Other (a)

     (144 )     (7 )     (137 )
                        

Total

   $ 1,592     $ 923     $ 669  
                        

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

 

Results of Operations—Generation

 

     2006     2005     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 9,143     $ 9,046     $ 97  

Operating expenses

      

Purchased power and fuel

     3,978       4,482       504  

Operating and maintenance

     2,305       2,288       (17 )

Depreciation and amortization

     279       254       (25 )

Taxes other than income

     185       170       (15 )
                        

Total operating expenses

     6,747       7,194       447  
                        

Operating income

     2,396       1,852       544  
                        

Other income and deductions

      

Interest expense

     (159 )     (128 )     (31 )

Equity in losses of unconsolidated affiliates

     (9 )     (1 )     (8 )

Other, net

     41       95       (54 )
                        

Total other income and deductions

     (127 )     (34 )     (93 )
                        

Income from continuing operations before income taxes

     2,269       1,818       451  

Income taxes

     866       709       (157 )
                        

Income from continuing operations

     1,403       1,109       294  

Discontinued operations

      

Gain on disposal of discontinued operations

     4       19       (15 )
                        

Income from discontinued operations

     4       19       (15 )
                        

Income before cumulative effect of changes in accounting principles

     1,407       1,128       279  

Cumulative effect of changes in accounting principles

     —         (30 )     30  
                        

Net income

   $ 1,407     $ 1,098     $ 309  
                        

 

Net Income. Generation’s net income for 2006 compared to 2005 increased due to higher revenue, net of purchased power and fuel expense partially offset by higher operating and maintenance expense, higher depreciation expense, higher interest expense and lower other income. The increase in Generation’s revenue, net of purchased power and fuel expense was due to realized revenues associated with forward sales contracts entered into in prior periods which were recognized at higher prices, combined with lower purchased power and fuel expense due to the impact of higher

 

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nuclear output. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. Generation’s net income for 2006 and 2005 reflects income from discontinued operations of $4 million and $19 million (after tax), respectively.

 

Operating Revenues. For 2006 and 2005, Generation’s sales were as follows:

 

Revenue

   2006    2005    Variance     % Change  

Electric sales to affiliates

   $ 4,674    $ 4,775    $ (101 )   (2.1 )%

Wholesale and retail electric sales

     3,640      3,341      299     8.9 %
                        

Total energy sales revenue

     8,314      8,116      198     2.4 %
                        

Retail gas sales

     540      613      (73 )   (11.9 )%

Trading portfolio

     14      17      (3 )   (17.6 )%

Other revenue (a)

     275      300      (25 )   (8.3 )%
                        

Total revenue

   $ 9,143    $ 9,046    $ 97     1.1 %
                        

(a) Includes sales related to tolling agreements, fossil fuel sales, operating service agreements and decommissioning revenue from ComEd and PECO.

 

Sales (in GWhs)

   2006    2005    Variance     % Change  

Electric sales to affiliates

   119,354    121,961    (2,607 )   (2.1 )%

Wholesale and retail electric sales

   71,326    72,376    (1,050 )   (1.5 )%
                  

Total sales

   190,680    194,337    (3,657 )   (1.9 )%
                  

 

Trading volumes of 31,692 GWhs and 26,924 GWhs for 2006 and 2005, respectively, are not included in the table above.

 

Electric sales to affiliates. Revenue from sales to affiliates decreased $101 million in 2006 as compared to 2005. The decrease in revenue from sales to affiliates was primarily due to a $95 million decrease from lower electric sales volume, as well as a net $6 million decrease resulting from lower prices.

 

In the ComEd territories, lower volumes resulted in a $115 million decrease in revenues as a result of lower demand resulting from milder weather year over year. In addition, price decreases totaling $128 million were a result of lower peak prices under the ComEd PPA.

 

In the PECO territories, the higher volumes resulted in increased revenues of $20 million due to higher usage. The favorable price variance of $122 million was primarily the result of the scheduled PAPUC-approved generation rate increase as well as to a lesser degree a change in the mix of average pricing related to the PPA with PECO. On January 1, 2007, a scheduled electric generation rate increase will take effect, which represents the last scheduled rate increase through 2010 under PECO’s 1998 restructuring settlement. This rate increase will have a favorable effect on Generation’s operating income in future years.

 

Wholesale and retail electric sales. The changes in Generation’s wholesale and retail electric sales for 2006 compared to 2005 consisted of the following:

 

    

Increase

(decrease)

 

Price

   $ 353  

Volume

     (54 )
        

Increase in wholesale and retail electric sales

   $ 299  
        

 

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Wholesale and retail sales increased $299 million due to an increase in realized revenues associated with forward sales entered into in prior periods, which were recognized at higher prices for the year ended December 2006, as compared to the same period in 2005, offset by a reduction in volumes sold into the market as a result of lower supply.

 

Retail gas sales. Retail gas sales decreased $73 million primarily due to lower volumes for 2006 compared to 2005, resulting in a $69 million decrease. Additionally, there was a decrease of $4 million due to lower realized prices for 2006 compared to 2005.

 

Other revenues. The decrease in 2006 was primarily due to a decrease in fossil fuel sales.

 

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

 

Supply Source (in GWhs)

   2006    2005    Variance     % Change  

Nuclear generation (a)

   139,610    137,936    1,674     1.2 %

Purchases—non-trading portfolio

   38,297    42,623    (4,326 )   (10.1 )%

Fossil and hydroelectric generation

   12,773    13,778    (1,005 )   (7.3 )%
                  

Total supply

   190,680    194,337    (3,657 )   (1.9 )%
                  

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

 

The changes in Generation’s purchased power and fuel expense for 2006 compared to 2005 consisted of the following:

 

(in millions)

   Price     Volume    

Increase

(Decrease)

 

Purchased power costs

   $ (81 )   $ (319 )   $ (400 )

Generation costs

     38       4       42  

Fuel resale costs

     34       (65 )     (31 )

Mark-to-market

     n.m.       n.m.       (115 )
            

Decrease in purchased power and fuel expense

       $ (504 )
            

n.m. Not meaningful

 

Purchased Power Costs. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation experienced a decrease of $319 million due to lower volumes of purchased power in the market as a result of a lower demand from affiliates. Additionally, overall lower prices paid for purchased power in 2006 compared to 2005 resulted in a $81 million decrease.

 

Generation Costs. Generation costs include fuel costs for internally generated energy. Generation experienced overall higher generation costs in 2006 compared to 2005 due to increased prices related to nuclear and fossil fuel generation, resulting in a $38 million increase.

 

Fuel Resale Costs. Fuel resale costs include retail gas purchases and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs in 2006 compared to 2005 were a result of a $65 million decrease in the retail gas business resulting from lower volumes, partially offset by overall higher prices paid for gas.

 

Mark-to-market. Mark-to-market gains on power derivative activities were $180 million in 2006 compared to losses of $12 million in 2005. Mark-to-market losses on fuel derivative activities were $77 million in 2006 compared to zero in 2005.

 

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Generation’s average margin per MWh of electricity sold for 2006 and 2005 was as follows:

 

($/MWh)

   2006    2005    % Change  

Average electric revenue

        

Electric sales to affiliates

   $ 39.16    $ 39.15    n.m.  

Wholesale and retail electric sales

     51.03      46.16    10.6 %

Total—excluding the trading portfolio

     43.60      41.76    4.4 %

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

   $ 18.02    $ 20.11    (10.4 )%

Average margin—excluding the trading portfolio

   $ 25.58    $ 21.65    18.2 %

(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.
n.m. Not meaningful

 

Nuclear fleet operating data and purchased power cost data for 2006 and 2005 were as follows:

 

     2006     2005  

Nuclear fleet capacity factor (a)

     93.9 %     93.5 %

Nuclear fleet production cost per MWh (a)

   $ 13.85     $ 13.03  

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

 

Although total refueling outage days increased during 2006 compared to 2005, the nuclear fleet capacity factor for the Generation-operating nuclear fleet increased due to fewer non-refueling outage days during 2006 compared to 2005. For 2006 and 2005, non-refueling outage days totaled 71 and 112, respectively, and refueling outage days totaled 237 and 217, respectively. Higher costs for nuclear fuel, costs associated with the additional planned refueling outage days, higher costs for refueling outage inspection and maintenance activities, costs for the tritium-related expenses, an NRC fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated resulting in a higher production cost per MWh produced for 2006 as compared to 2005. There were ten planned refueling outages and sixteen non-refueling outages during 2006 compared to nine planned refueling outages and twenty-five non-refueling outages during 2005 at the Generation-operated nuclear stations.

 

Operating and Maintenance Expense. The increase in operating and maintenance expense for 2006 compared to 2005 consisted of the following:

 

    

Increase

(decrease)

 

Pension, payroll and benefit costs

   $ 153  

Contractor expenses

     22  

Nuclear refueling outage costs including the co-owned Salem plant

     19  

NRC fees

     11  

Godley contribution

     11  

Tritium-related expense

     9  

Reduction in ARO (a)

     (149 )

2005 accrual for estimated future asbestos-related bodily injury claims (b)

     (43 )

2005 co-owner settlement with PSEG related to postretirement benefits

     (17 )

Other

     1  
        

Increase in operating and maintenance expense

   $ 17  
        

(a) For further discussion, see Note 13 of the Combined Notes to Consolidated Financial Statements.
(b) For further discussion, see Note 18 of the Combined Notes to Consolidated Financial Statements.

 

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The $17 million increase in operating and maintenance expense in 2006 compared to 2005 was primarily due to a $153 million increase in various payroll-related expenses, including increased stock-based compensation expense of $41 million primarily as a result of the adoption of SFAS No. 123-R as of January 1, 2006 and increased direct and allocated costs related to payroll, severance, pension and other postretirement benefits, a $22 million period-over-period increase in contractor costs, primarily related to staff augmentation and recurring maintenance work at Nuclear and Power, a $19 million increase in nuclear refueling outage costs associated with the additional planned refueling outage days during 2006 as compared to 2005, and higher costs for inspection and maintenance activities. Additionally, on December 22, 2006, as a gesture of goodwill and corporate citizenship, Generation contributed approximately $11 million into an escrow account to assist the Godley Public Water District with the installation of a new public drinking water system for the Village of Godley.

 

Depreciation and Amortization. The increase in depreciation and amortization expense for 2006 compared to 2005 was a result of recent capital additions.

 

Taxes Other Than Income. The increase in taxes other than income incurred during 2006 compared to 2005 was primarily due to increasing the property tax reserve for 2006 property taxes for Byron, Clinton and Dresden, higher payroll related taxes which were the result of higher payroll costs for 2006 and a reduction recorded in 2005 of a previously established real estate reserve associated with the settlement over the TMI real estate assessment. The increases were partially offset by a sales and use tax reserve recorded during the third quarter of 2005 and a gas revenue tax adjustment recorded during the fourth quarter of 2005.

 

Interest Expense. The increase in interest expense during 2006 as compared to 2005 was attributable to higher variable interest rates on debt outstanding, higher interest expense on Generation’s one-time fee for spent nuclear fuel obligations to the DOE and an interest payment made to the IRS in settlement of a tax matter.

 

Other, Net. The decrease in other income in 2006 compared to 2005 was primarily due to gains realized in the second quarter of 2005 totaling $36 million related to the decommissioning trust fund investments for the AmerGen plants due to changes in Generation’s investment strategy.

 

Effective Income Tax Rate. The effective income tax rate from continuing operations was 38.2% for 2006 compared to 39.0% for 2005. See Note 12 of the Combined Notes to Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

 

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 and Comprehensive Income. Generation’s net income in 2006 and 2005 reflects a gain on the sale of discontinued operations of $4 million and $19 million (both after tax), respectively. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

 

The income from discontinued operations decreased by $15 million for 2006 compared to 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005 partially offset by an adjustment to the gain on the sale of Sithe in the second quarter of 2006 as a result of the expiration of certain tax indemnifications, accrued interest and collections on receivables arising from the sale of Sithe that had been fully reserved.

 

Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles reflects the impact of adopting FIN 47 as of December 31, 2005. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

 

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Results of Operations—ComEd

 

     2006     2005     Favorable
(unfavorable)
variance
 

Operating revenues

   $ 6,101     $ 6,264     $ (163 )

Operating expenses

      

Purchased power

     3,292       3,520       228  

Operating and maintenance

     745       833       88  

Impairment of goodwill

     776       1,207       431  

Depreciation and amortization

     430       413       (17 )

Taxes other than income

     303       303       —    
                        

Total operating expense

     5,546       6,276       730  
                        

Operating income (loss)

     555       (12 )     567  
                        

Other income and deductions

      

Interest expense, net

     (308 )     (291 )     (17 )

Equity in losses of unconsolidated affiliates

     (10 )     (14 )     4  

Other, net

     96       4       92  
                        

Total other income and deductions

     (222 )     (301 )     79  
                        

Income (loss) before income taxes and cumulative effect of a change in accounting principle

     333       (313 )     646  

Income taxes

     445       363       (82 )
                        

Loss before cumulative effect of a change in accounting principles

     (112 )     (676 )     564  

Cumulative effect of change in accounting principle

     —         (9 )     9  
                        

Net loss

   $ (112 )   $ (685 )   $ 573  
                        

 

Net Loss. ComEd’s decreased net loss in 2006 compared to 2005 was driven by a smaller impairment of goodwill in 2006, lower purchased power expense and one-time benefits associated with reversing previously incurred expenses as a result of the July 2006 and December 2006 ICC rate orders as more fully described below, partially offset by lower operating revenues.

 

Operating Revenues. The changes in operating revenues for 2006 compared to 2005 consisted of the following:

 

    

Increase

(decrease)

 

Weather

   $ (226 )

Customer choice

     (67 )

Volume

     84  

Rate changes and mix

     23  
        

Retail revenue

     (186 )
        

Wholesale and miscellaneous revenues

     28  

Mark-to-market contracts

     (5 )
        

Other revenues

     23  
        

Decrease in operating revenues

   $ (163 )
        

 

Weather. Revenues were lower due to unfavorable weather conditions in 2006 compared to 2005. The demand for electricity is affected by weather conditions. Very warm weather in summer months

 

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and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather in non-summer months reduces demand. In ComEd’s service territory, cooling and heating degree days were 20% and 8% lower, respectively, than the prior year.

 

Customer choice. All ComEd customers have the choice to purchase energy from a competitive electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. As of December 31, 2006, one competitive electric generation supplier had been granted approval to serve residential customers in the ComEd service territory. However, they are not currently supplying electricity to any residential customers.

 

For 2006 and 2005, 23% and 21%, respectively, of energy delivered to ComEd’s retail customers was provided by competitive electric generation suppliers. Most of the customers previously receiving energy under the PPO are now electing either to buy their power from a competitive electric generation supplier or from ComEd under bundled rates.

 

     2006     2005  

Retail customers purchasing energy from a competitive electric generation supplier:

    

Volume (GWhs) (a)

   20,787     19,310  

Percentage of total retail deliveries

   23 %   21 %

Retail customers purchasing energy from a competitive electric generation supplier or the ComEd PPO:

    

Number of customers at period end

   20,300     21,300  

Percentage of total retail customers

   (b )   (b )

Volume (GWhs) (a)

   25,521     30,905  

Percentage of total retail deliveries

   28 %   33 %

(a) One GWh is the equivalent of one million kilowatthours (kWh).
(b) Less than one percent.

 

Volume. Revenues were higher in 2006 compared to 2005 due primarily to an increase in deliveries, excluding the effects of weather, due to an increased number of customers.

 

Rate changes and mix. The increase in revenue related to rate and mix changes represents differences in year-over-year consumption between various customer classes offset by a decline in the CTC paid by customers of competitive electric generation suppliers due to the increase in market energy prices. The average rate paid by various customers is dependent on the amount and time of day that the power is consumed. Changes in customer consumption patterns, including increased usage, can result in an overall decrease in the average rate even though the tariff or rate schedule remains unchanged. Under current Illinois law, no CTCs will be collected after 2006. Starting in January 2007, ComEd began collecting revenues consistent with the approved ICC orders in the Procurement Case and the Rate Case. See Note 4 of the Combined Notes to the Consolidated Financial Statements for more information.

 

Wholesale and miscellaneous revenues. The wholesale and miscellaneous revenues increase primarily reflects an increase in transmission revenue reflecting increased peak and kWh load within the ComEd service territory.

 

Mark-to-market contracts. Mark-to-market contracts primarily reflect a mark-to-market loss associated with one wholesale contract that had previously been recorded as a normal sale under SFAS No. 133 in 2005. This contract expires in December 2007.

 

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Purchased Power Expense. The changes in purchased power expense for 2006 compared to 2005 consisted of the following:

 

    

Increase

(decrease)

 

Prices

   $ (135 )

Weather

     (111 )

Customer choice

     (56 )

PJM transmission

     (6 )

Volume

     42  

SECA rates

     38  
        

Decrease in purchased power expense

   $ (228 )
        

 

Prices. Purchased power decreased due to the decrease in contracted energy prices under the PPA that ComEd had with Generation. The PPA contract was entered into in March 2004 and reflected forward power prices in existence at that time. The PPA terminated at the end of 2006 and was replaced with the reverse-auction process in 2007, which was approved by the ICC. See Note 4 of the Combined Notes to Consolidated Financial Statements for more information on the reverse-auction process.

 

Weather. The decr